Systems for extracting fluids from the earth&#39;s subsurface and for generating electricity without greenhouse gas emissions

ABSTRACT

An embodiment is an apparatus for generating a driver gas, for recovering fluid from the Earth&#39;s subsurface. The apparatus includes a fuel reformer, adapted to react a fuel with water to produce carbon dioxide gas and hydrogen gas; a compressor, adapted to compress a portion of the carbon dioxide gas and a portion of the hydrogen gas; a gas injection unit, adapted to inject the portion of the carbon dioxide gas and the portion of the hydrogen gas compressed by the compressor, into a subsurface reservoir; a gas capture unit, adapted to capture a portion of the carbon dioxide gas and the hydrogen gas, that emerges from the subsurface reservoir; and a control module capable of using subsurface data to regulate operation of the gas injection unit. The apparatus may also include a power generator adapted to utilize a portion of the hydrogen gas to generate power, hence producing electricity without greenhouse gas emissions.

REFERENCE TO RELATED APPLICATIONS

This application claims priority from co-pending U.S. application Ser.No. 11/751,028 entitled “Portable and modular system for extractingpetroleum and generating power” to Robert Zubrin et al., filed on May20, 2007, the entirety of which are is hereby incorporated by referenceherein.

FIELD OF THE INVENTION

This invention relates to extracting hydrocarbons, such as petroleum andnatural gas, and to generating electricity without greenhouse gasemissions. More particularly, the present invention relates to aportable and modular system/apparatus that may be taken to a location ofan oil field, and especially a “depleted” oil well, and used to extractoil and/or generate electricity.

BACKGROUND OF THE INVENTION

Currently there are tens of thousands of depleted oil and natural gaswells around the world, which collectively possess significant amountsof petroleum resources that cannot currently be extracted usingconventional extraction techniques.

For example, in a typical oil well, only about 30% of the undergroundoil is recovered during initial drilling (“primary recovery”). Anadditional approximately 20% of the original oil may be accessed by“secondary recovery” techniques such as water flooding. In recent years,“tertiary recovery” (also known as “Enhanced Oil Recovery” or EOR)techniques have been developed to recover additional oil from depletedwells. Such tertiary recovery techniques include thermal recovery,chemical injection, and gas injection. Using current methods, thesetertiary techniques allow for an additional 20% or more of the originaloil to be recovered.

Gas injection is one of the most common EOR techniques. In particular,carbon dioxide (CO₂) injection into depleted oil wells has receivedconsiderable attention owing to its ability to mix with crude oil. Sincecrude oil is miscible with CO₂ at moderate pressures and temperatures,injection of CO₂ renders the oil substantially less viscous and moreamenable to recovery.

Despite the potential advantages of CO₂ in enhanced oil recovery, itsuse has been hampered by several factors. For instance, in order for theenhanced recovery process to be economically viable, the CO₂ gas must beavailable in copious supplies at reasonable cost at the site of the oilwell. Alternatively, CO₂ can be produced from industrial applicationssuch as natural gas processing, fertilizer, ethanol and hydrogen plantswhere naturally occurring CO₂ reservoirs are not available. The CO₂ mustthen be transported over large distances via pipelines and injected atthe well site. Unfortunately, such CO₂ pipelines are difficult andcostly to construct. Additionally, many oil sites are out of reach fromsuch natural and industrial sources of CO₂.

Additionally, as a result of widespread concern over global warming,proposals are being considered to create taxes on CO₂ emissions, withtypical figures in the range of $50 per tone of CO₂ released into theatmosphere. However, most electric power plants, which burn coal ornatural gas to generate electricity, produce large quantities of CO₂waste product. Using present technologies, it is often not economicallyfeasible to utilize the CO₂ from such power plants for oil recoverybecause they are not within close reach of oil fields. Thus, the cost ofsequestering CO₂ in the ground is often not economically feasible.

In addition to CO₂, another gas that can potentially be used forenhanced oil recovery is hydrogen (H₂). Hydrogen gas has receivedconsiderably less attention than CO₂, however. Hydrogen, althoughsomewhat soluble with oil, is far less so than CO₂. Large quantities ofhydrogen are believed to be necessary for pressurization and longresidence times are believe necessary for in-situ hydrogenation.Traditionally, hydrogen has been costly to produce and its use has notbeen justified from an economic standpoint.

Accordingly, as recognized by the present inventors, what is needed is aportable and modular system and apparatus that may be taken wherever acandidate oil field may be, for extracting oil/petroleum from the groundor from oil wells, such as “depleted” oil wells. What is also needed isa modular system and apparatus that may be taken wherever a natural gasreservoir may be, for extracting natural gas from the ground or fromnatural gas wells.

Additionally, as recognized by the present inventors, what are alsoneeded are a system, a method, and an apparatus for generating power,such as electricity, while emitting less CO₂ into the atmosphere. Whatare also needed are a system, a method, and an apparatus for utilizingcoal, natural gas, or other fossil fuels to produce power, such aselectricity, without incurring large CO₂ tax penalties.

Therefore, it would be an advancement in the state of the art to providea portable and modular system and apparatus that may be taken wherever acandidate oil or natural gas field may be, and which may be used togenerate large quantities of CO₂ and hydrogen gas for use in enhancedoil recovery, as well as to generate electricity without emitting largequantities of CO₂ into the atmosphere.

It is against this background that various embodiments of the presentinvention were developed.

BRIEF SUMMARY OF THE INVENTION

One embodiment of the present invention is a portable apparatus forgenerating a gas mixture that may be used to drive currentlyunrecoverable oil from a near-depleted, or depleted, oil reservoir. Anembodiment of the present invention is a portable, highly economic CO₂generation system. This embodiment also generates large supplies ofhydrogen. In one embodiment of the present invention, the hydrogen gasis injected into the oil well, either separately or in combination withthe CO₂ gas. In another embodiment of the present invention, thehydrogen gas is used to generate power in the form of electricity. Oneembodiment of the present invention is a portable, modular system thatmay be delivered to the site of the oil well by various methods oftransportation, including a truck, a boat, or an airplane. The scale ofthe present invention is simultaneously portable and also sized togenerate sufficient driver gas for economic recovery of oil.

In one embodiment of the present invention, the portable apparatusgenerates CO₂ and hydrogen by a reforming reaction. The CO₂ is injectedinto the oil or natural gas well while the hydrogen is split off fromthe CO₂ product to be used for other purposes, including electricalpower generation or petrochemical processing. As will be discussedbelow, the hydrogen may also be injected simultaneously with the CO₂into the oil well for enhanced oil recovery. Depending upon variousfactors such as the particular composition of the underground oil, aswell as the local cost of electrical power, an operator of the presentinvention may find it advantageous to use hydrogen in differentproportions for these various purposes. In an alternative embodiment,the hydrogen may be injected by itself into the oil well while the CO₂may be used for other purposes.

In light of the above and according to one embodiment of the presentinvention, disclosed herein is an apparatus for generating a driver gas,for recovering oil or natural gas from a subsurface reservoir (“theapparatus”). The apparatus includes a fuel reformer, adapted to react afuel with water to produce carbon dioxide gas and hydrogen gas; acompressor, adapted to compress a portion of the carbon dioxide gas anda portion of the hydrogen gas; a gas injection unit, adapted to injectthe portion of the carbon dioxide gas and the portion of the hydrogengas compressed by the compressor, into the subsurface reservoir; a gascapture unit, adapted to capture a portion of the carbon dioxide gas andthe hydrogen gas, that emerges from the subsurface reservoir; and acontrol module capable of using subsurface data to regulate operation ofthe gas injection unit.

Another embodiment of the present invention is the apparatus describedabove that also includes a heat exchanger adapted to enhance thermalefficiency of the fuel reformer.

Another embodiment of the present invention is the apparatus describedabove that also includes a gas separator, adapted to separate the carbondioxide gas from the hydrogen gas.

Another embodiment of the present invention is the apparatus describedabove that also includes a power generator adapted to utilize a portionof the hydrogen gas separated by the gas separator to generate power.Since the CO₂ is injected into the Earth's subsurface for enhanced oilrecovery, power/electricity is generated without greenhouse gasemissions into the Earth's atmosphere.

Another embodiment of the present invention is the apparatus describedabove where the power generator is a gas turbine, an internal combustionengine, or a fuel cell unit.

Another embodiment of the present invention is the apparatus describedabove that also includes a chassis adapted to support the fuel reformer,the compressor, the gas injection unit, the gas capture system, thecontrol module, the gas separator, and the power generator.

Another embodiment of the present invention is the apparatus describedabove where the recaptured carbon dioxide gas and hydrogen gas arecompressed by the compressor and injected by the gas injection unit backinto the subsurface reservoir.

Another embodiment of the present invention is the apparatus describedabove that also includes a chassis adapted to support the fuel reformer,the compressor, the gas injection unit, the gas capture system, and thecontrol module. The chassis may contain one or more wheels for surfacetransportation.

Another embodiment of the present invention is the apparatus describedabove where wherein the chassis is operable to be hauled by a vehicle.Another embodiment of the present invention is the apparatus describedabove where the chassis is adapted to be attached to a truck, a train, awater vessel, or an aircraft. Since the chassis may be attached to anyappropriate transportation vehicle, the apparatus of the presentinvention is portable and may be taken to a site of any oil field,including distant, far-off, and off-shore oil fields, and those locatedin rugged, coarse, and unfriendly terrain.

Another embodiment of the present invention is the apparatus describedabove that also includes a gas injection line, operatively connected tothe gas injection unit, and adapted to inject the portion of the carbondioxide gas and the portion of the hydrogen gas to a predetermined depthwithin the subsurface reservoir.

Another embodiment of the present invention is the apparatus describedabove where the gas is injected into an oil well, or a natural gas well.

Another embodiment of the present invention is a portable apparatusadapted to extract fluid from the Earth's subsurface (“the apparatus”).The apparatus includes a chassis for supporting a fuel reformer, acompressor, and a control module; the fuel reformer, capable of reactinga material with water to produce a mixture of carbon dioxide gas andhydrogen gas; the compressor, capable of compressing at least a portionof the carbon dioxide gas and a portion of the hydrogen gas intended forinjection into the Earth's subsurface; and the control module capable ofusing subsurface data to regulate the operation of the fuel reformer andthe compressor.

Another embodiment of the present invention is the apparatus describedabove that also includes one or more wheels attached to the chassis.

Another embodiment of the present invention is the apparatus describedabove that also includes a gas capture unit capable of recapturing aportion of the carbon dioxide gas and a portion of the hydrogen gas thatis released from the orifice.

Another embodiment of the present invention is the apparatus describedabove that also includes a gas injection line, operably connected to thecompressor, and adapted to inject the portion of the carbon dioxide gasand the portion of the hydrogen gas to a predetermined depth within theEarth's subsurface.

Another embodiment of the present invention is the apparatus describedabove where the fuel includes organic material feedstock.

Another embodiment of the present invention is the apparatus describedabove where the fuel is coal, coal/water slurries, crude oil, crop,forestry residues, biomass, alcohols, natural gas, refined petroleumproducts, oil shale, tars, and/or industrial waste products.

Another embodiment of the present invention is the apparatus describedabove that also includes a fuel purification module for purifying intakefuel for use in the fuel reformer.

Another embodiment of the present invention is the apparatus describedabove where the fuel purification module is adapted to purify intakecoal.

Another embodiment of the present invention is the apparatus describedabove where the gas separator includes sorption beds, carbon dioxidefreezers, membranes, or centrifugal separators.

Another embodiment of the present invention is a system for recoveringfluid from the Earth's subsurface (“the system”). The system includes atleast one orifice leading to at least one hole; a fuel reformer, adaptedto react a fuel with water to produce driver gas; a compressor, adaptedto compress the driver gas; and an injection line, operably connected tothe compressor and leading into the Earth's subsurface via the orifice,adapted to inject the driver gas a predetermined depth down the hole.

Another embodiment of the present invention is the system describedabove that also includes a gas capture unit, adapted to capture aportion of the driver gas that returns from the Earth's subsurface.

Another embodiment of the present invention is the system describedabove that also includes a control module capable of using down-holedata to regulate operation of the compressor.

Another embodiment of the present invention is the system describedabove that also includes a power generator adapted to utilize a portionof the driver gas to generate power. Yet another embodiment of thepresent invention is a system for recovering oil from an oil field (“thesystem”). The system includes at least one opening leading to at leastone oil well; a fuel reformer, adapted to react a fuel with water toproduce carbon dioxide gas and hydrogen gas; a compressor, adapted tocompress a portion of the carbon dioxide gas and a portion of thehydrogen gas; and an injection line, operably connected to thecompressor and leading down the oil well via the opening, adapted toinject the driver gas a predetermined depth down the oil well.

Another embodiment of the present invention is the system describedabove that also includes a gas capture unit, adapted to capture aportion of the carbon dioxide gas and the hydrogen gas that emerges withthe oil from the oil well.

Another embodiment of the present invention is the system describedabove that also includes a control module capable of using data from theoil well to regulate operation of the compressor.

Another embodiment of the present invention is the system describedabove that also includes a power generator adapted to utilize a portionof the hydrogen gas to generate power.

Another embodiment of the present invention is the system describedabove where electrical power is generated at or near the oil field andfed into an electrical grid.

Another embodiment of the present invention is the system describedabove where the power generated is electrical power, mechanical power,and/or steam power.

In one example of the above apparatus in operation, a mixture ofhydrogen, carbon dioxide, and possibly other gases (“driver gas”) isgenerated by reforming a fuel source, such as coal, with water. Aportion of the hydrogen gas is separated from the driver gas mixture byusing a gas separator, such as a sorption bed. A portion of the hydrogengas thus separated may be used to generate power, such as by burning thehydrogen gas in a gas turbine to generate electricity. Finally, aportion of the driver gas, including a portion of the hydrogen gas andthe carbon dioxide gas, are injected into an oil well for enhanced oilrecovery. Therefore, power (e.g., electricity), may be generated withless harmful release of carbon dioxide into the atmosphere. In addition,the carbon dioxide gas is generated at a cost that is economicallysuitable for enhanced oil recovery. No expensive CO₂ pipelines arenecessary since a portable and modular apparatus generates the carbondioxide on-site.

Other embodiments of the present invention include methods correspondingto various steps the above apparatus may perform. Other features,utilities and advantages of the various embodiments of the inventionwill be apparent from the following more particular description ofembodiments of the invention as illustrated in the accompanyingdrawings.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates an example of an embodiment of the present inventionfor the extraction of oil from an oil well;

FIG. 2 illustrates an example of operations for extracting oil from anoil well, in accordance with an embodiment of the present invention;

FIG. 3 illustrates an example of an indirect fuel reformer, which servesas part of an apparatus for extracting oil from an oil well, inaccordance with an embodiment of the present invention;

FIG. 4 illustrates an autothermal fuel reformer, which serves as part ofan apparatus for extracting oil from an oil well, in accordance with anembodiment of the present invention;

FIG. 5 illustrates an example of a system utilizing a fixed-bed reformerfor extracting oil from an oil well, in accordance with an embodiment ofthe present invention;

FIG. 6 illustrates an example of a system utilizing a fluidized-bedreformer for extracting oil from an oil well, in accordance with anembodiment of the present invention;

FIG. 7 illustrates an example of a system utilizing a natural gasreformer for extracting oil from an oil well, in accordance with anembodiment of the present invention;

FIG. 8 illustrates an example of a system utilizing a portion of thelocally recovered oil for extracting oil from an oil well, in accordancewith an embodiment of the present invention;

FIG. 9 illustrates a chassis used to support one or more modulesaccording to an embodiment of the present invention;

FIG. 10 illustrates an example of an embodiment of the present inventionfor the extraction of oil from an oil well and for the generation ofelectrical power;

FIG. 11 illustrates an example of operations for extracting oil from anoil well and for generating electricity, in accordance with anembodiment of the present invention;

FIG. 12 illustrates another example of an embodiment of the presentinvention for the extraction of oil from an oil well and for thegeneration of electrical power;

FIG. 13 illustrates an economic model comparing financial multipliersfor various fuel combinations for a system generating 250 kcf of carbondioxide per day;

FIG. 14 illustrates an economic model comparing financial multipliersfor various fuel combinations for a system generating 1,000 kcf ofcarbon dioxide per day; and

FIG. 15 illustrates a parametric economic model comparing financialmultipliers for various feedstock materials as a function of thehydrogen effectiveness relative to carbon dioxide effectiveness inenhancing oil recovery.

DETAILED DESCRIPTION OF THE INVENTION

Throughout this disclosure, the symbol “kcf” shall mean “thousandstandard cubic feet,” usually of CO₂ unless explicitly stated otherwise.The symbol “MMcf” shall mean “million standard cubic feet,” usually ofCO₂ unless explicitly stated otherwise. That is, a reformer thatproduces 1 kcf/day of driver gas produces 1,000 standard cubic feet ofdriver gas per day, while a reformer that produces 1 MMcf/day of drivergas produces 1,000,000 (1 million) standard cubic feet of driver gas perday. Please note that other sources may use different symbols, such as“mcf” for “thousand cubic feet” based on the Roman numeral “M” forthousand, and care should be taken in terminology when consulting suchsources. The word “day” shall mean “a day of operations,” which could bean 8-hour day, a 12-hour day, a 24-hour day, or some other amount oftime, depending on how a particular oil field is being operated.

An embodiment of the present invention is a Driver Gas Generation System(DGGS) whose purpose is to generate a gas mixture that can be used todrive currently unrecoverable oil out of the ground for commercial use.In one embodiment of the present invention, the DGGS may be configuredto generate electricity using a portion of the gas mixture. According toone embodiment of the present invention, the DGGS is a modular system,which can include all or part of a set of primary components or modules.The modules may include a chassis to support the other modules, a fuelreformer module for generating the driver gas, heat exchangers forenhanced thermal efficiency, a gas separator module for separatinghydrogen from the driver gas, a compressor module for compressing thedriver gas, a power generator module for generating power from thehydrogen gas, a control module for controlling the other modules, and agas capture module for capturing some of the driver gas emerging withthe oil. These modular components may be mixed and matched depending onthe particular application, the requirements of a particular operator,or the conditions of a particular oil field.

A chassis for supporting the other sub-systems, or modules, is provided.The chassis may be attached to an appropriate method of transportation,such as a truck, boat, or aircraft. The chassis, carrying the variousmodules, may be mounted or carried upon any number of differentvehicles. The chassis may have one or more wheels, or it may have nowheels and may instead rely on the wheels of the vehicle. Thisconfiguration makes the system highly portable, and allows it to beeasily transported to the location of any oil well, including off-shoreand remote wells. The chassis is illustrated in FIGS. 9 and 10. Variouschassis configurations are possible, and the present invention is notlimited to the chassis configuration and design illustrated here.

A fuel reformer module, capable of reacting a fuel with water to producea mixture of CO₂ and hydrogen gas, sized to an output rate appropriatefor enhanced oil recovery operations, is provided. Depending upon theavailability and cost of local fuel types, the reformer modules may bedesigned to operate with various candidate organic material feedstock,including coal, crude oil, crop or forestry residues or other forms ofbiomass, alcohols, natural gas, refined petroleum products, oil shale,tars, and urban, industrial, or rural waste products. In one embodimentof the present invention, an operator is provided with multiple reformermodules to choose from. The operator would select the appropriatereformer module based on local parameters and detailed economicmodeling, as will be described in detail below. Examples of the designof the reformer module are provided below, and may include a methanolreformer, a coal reformer, a methane reformer, a local oil reformer, orany other type of reformer module using any other type of feedstockmaterial. Two examples of reformer modules are illustrated in FIGS. 3and 4. Various reformer modules are within the scope of the presentinvention, so long as the reformer modules generate driver gas from afuel source.

A set of heat exchangers, designed to maximize the thermal efficiency ofthe reformer module as well as the efficiency of the overall system, areprovided. The heat exchangers are discussed below in relation to thefuel reformer modules, and illustrated in FIGS. 3 and 4. Various heatexchangers are within the scope of the present invention, and are notlimited to the design and configuration illustrated and described here,so long as the heat exchangers perform the function of increasingthermal efficiency of the reformer module or other system modules.

A gas separator module, capable of separating the CO₂ from the hydrogen,is provided. This module gives an operator of the DGGS a choice of howmuch hydrogen to send underground with the CO₂, and how much to retainfor surface utilization. Candidate separator modules use membranes,Pressure Swing Absorption (PSA), regenerable sorption beds, scrubbing inamine solution, CO₂ freezers, or centrifugal separation, and aredescribed in detail below. Various gas separator modules may be used,and the present invention is not limited to the particular gasseparators shown or described herein, so long as the gas separatorsperform at least the function of separating hydrogen gas from the restof the driver gas.

A compressor module, capable of compressing the driver gas to a pressureappropriate for oil recovery, is provided. The compressor module iscapable of compressing the CO₂ as well as a portion of the hydrogenintended for underground use, to a pressure appropriate for injectioninto the oil well. Numerous types of gas compressor modules may be usedto compress the driver gas before injection into the oil well. Variouscompressors are within the scope of the present invention, and are notlimited to the designs and configurations illustrated and describedhere, so long as the compressors can compress the driver gas to apressure appropriate for injection into the oil well.

An injection module as well as an injection line, capable of sending thedriver gas deep into the oil well for use in oil extraction, areprovided. The injection module may be a port, a hole, or interlockingmechanism for connecting the compressor module to the injection line.The injection line feeds the driver gas down the injection well. Variousinjection modules and injection lines are within the scope of thepresent invention, and are not limited to the various designs andconfigurations illustrated and described here.

A power generator module, capable of utilizing the hydrogen gasseparated by the gas separated to generate electricity, is provided. Thepower generator module may be a gas turbine, an internal combustionengine, a fuel cell, or any other apparatus, system, or module that cangenerate power (electrical or mechanical or other) from hydrogen gas.The power generated on-site by the power generator module may be used tosupport driver gas production processes occurring in the reformer moduleas well as driver gas compression (compressor module) and injection. Insome scenarios, an excess of power is available and may be fed throughthe electrical power grid to generate additional revenue. Various powergenerator modules are within the scope of the present invention, and arenot limited to the particular power generators shown or described here,so long as the power generators can generate power from hydrogen gas.

A control module, capable of controlling the operation of the DGGS bothautomatically and with user-input, is provided. The control module mayuse subsurface data to automatically regulate the operation of thesystem via feedback control. This allows the DGGS to operate withminimal human supervision or labor. The control module also provides aninterface for an operator to control, maintain, and supervise theoperation of the DGGS. Various control modules as well as controlmethods are within the scope of the present invention, and the presentinvention is not limited to the particular control modules or controlmethods shown or described here.

A gas capture module, capable of re-capturing a portion of the drivergas emerging with the oil and recycling the driver gas back into the oilwell, is provided. The gas capture module allows the CO₂ and hydrogenthat is released from the oil emerging from the ground to be re-capturedand sent via the compressor module and the injection module backunderground for reuse. The gas capture module increases the overallefficiency of the oil recovery operation, because a portion of thegenerated driver gas is recycled and reused. Various gas capture modulesare within the scope of the present invention, and the present inventionis not limited to the particular gas capture modules or methods shown ordescribed here, as long as the gas capture modules or methods arecapable of capturing at least a portion of the driver gas emerging withthe oil from the oil well.

The various modules are appropriately interconnected after being placedon the chassis. The operation, inter-connection, and use of the variousmodules are described in greater detail throughout this disclosure.These modular components may be mixed and matched by an operator of thepresent invention in appropriate combinations based on local conditionsand market prices. For example, if the oil site has a high powerrequirement, or the local cost of electricity is high, the H₂ gas may beseparated from the CO₂ gas using a gas separator, and the H₂ gas may beburned in a gas turbine to generate electricity. The electricity may beused on-site to provide power for the oil field, or else sold to anelectric distribution company to generate additional revenue by feedingthe electricity into the electric grid. Therefore, a portable andmodular system is created for enhancing oil recovery wherever acandidate oil field may be, including off-shore and remote oil fields.

Embodiments of the present invention provide for the creation of drivergas which is used for extracting oil from an otherwise depleted oilwell, or to drive trapped reservoirs of underground natural gas to thesurface. For purposes of the present invention, a driver gas istypically any gas formed during the reforming reactions of the presentinvention and is preferably a carbon dioxide-rich gas or hydrogen andcarbon dioxide containing gas. Various embodiments of the presentinvention are disclosed herein. Note that the majority of the disclosureis directed toward creating a driver gas that is ultimately injectedinto depleted oil wells for the extraction of oil; however, methods andapparatus according to the present invention can also be used to createdriver gases useful in driving trapped natural gas to the surface. Assuch, it is noted that the scope of the present invention encompassesthe use of driver gas created in accordance with the present inventionto drive out other liquids or materials other than oil from depleted oilwells, and in particular encompasses using driver gas to drive trappednatural gas out of underground natural gas reservoirs.

In FIG. 1, an underground oil well 100 (which may be otherwise“depleted”) is illustrated, having an amount of oil therein, such as aresidual amount of oil. The simplest configuration of the DGGS, having areformer module and a compressor module, is first discussed. A portable,self-contained reformer module 102 in accordance with the presentinvention generates driver gas (shown as arrow 104) that may be pumpedinto the oil well for removing the residual oil 109 from the oil well100. As explained herein, the reformer module 102 may reform or reactfuel sources (shown as arrow 105) such as coal, alcohols, olefins,paraffins, ethers, aromatic hydrocarbons, and other like materials (ormixtures thereof) with (shown as arrow 107) (or without) water to formdriver gas 104 which, in one example, is a hydrogen and carbon dioxidegas mixture. The driver gas 104 is then compressed by a compressormodule 106 into high pressure gas that could be pumped underground (seeline 108) where it could impose pressure on residual undergroundpetroleum 109 sufficient to allow it to be extracted by the same oilwell, a nearby oil well 110, or other like site. As shown in FIG. 1, allof the driver gas, including both the carbon dioxide and hydrogen, maybe injected into the well for the purposes of oil recovery. In analternative embodiment, not shown in FIG. 1 and described later, all orpart of the hydrogen may be separated from the carbon dioxide and,instead of being injected into the oil well, used for alternativepurposes such as the generation of electric power or the hydrogenationof oil.

FIG. 2 illustrates an example of operations that may be performed inorder to drive petroleum resources out of the ground, such as out of anoil well or a depleted oil well. At operation 1 (shown as element 200),a fuel source is reformed into driver gas. In one example, operation 1may include combustion of a material 202 such as coal or methanol, inorder to provide energy, for instance, within a combustion chamber. Theenergy generated from the combustion may be used to heat the reformingreaction fuel source to a temperature where the fuel source reacts with(or without) water to form a hydrogen and carbon dioxide rich driver gas204. Note that the energy used to drive the reforming reaction can alsobe provided from a non-combustible source, for example, solar energy,nuclear energy, wind energy, grid electricity, or hydroelectric power(shown as element 206).

At operation 2 (shown as element 208), the driver gas is injected intothe oil well in order to drive petroleum out of the ground 210. Forinstance, the injected gas may soften highly viscous petroleum residuesand displace them, thereby mobilizing such petroleum residues forrecovery by conventional means (shown as element 212).

Reformer Modules

Embodiments of the present invention provide reformer modules forgenerating driver gas used in petroleum extraction, from among othersites, depleted oil wells. Embodiments of the reformer modules accordingto the present invention are portable, self-contained, and energyefficient, and are able to generate driver gas through reforming of afuel source. In some embodiments, the reformer modules utilizes areforming reaction to generate the driver gas and a combustion reactionto provide the energy required to reform a fuel and generate the drivergas.

In general, the reformer module is an apparatus that may generate carbondioxide and hydrogen gas mixtures by reforming a fuel source with water.The fuel source may be one of a number of different materials, includingcoal, methane (natural gas), methanol, other alcohols, or even a portionof the local oil extracted from the oil well.

In one example, the reformer module reforms or reacts a fuel or otherhydrocarbon source with water to generate hydrogen and carbon dioxide“driver gas” mixtures. The driver gas is injected into the oil well forenhanced oil recovery. The fuel or hydrocarbon sources used for thegeneration of driver gas include, but are not limited to, alcohols,olefins, paraffins, ethers, aromatic hydrocarbons, solid hydrocarbons(such as coal), and the like. In addition, the fuel sources can berefined commercial products such as propane, diesel fuels, gasolines orunrefined commercial products such as crude oil, natural gas, or solidhydrocarbons (such as coal). The water can be introduced into thereforming reactor as liquid water, as steam, or, if the fuel is analcohol or other substance miscible in water, as a component premixedwith the fuel.

In some embodiments of the reformer module, the fuel source for thereforming reaction is an unrefined product such as crude oil, and insome embodiments, crude oil captured from the same oil well into whichthe driver gas is being injected.

The reforming reaction can be driven by the release of energy from acombustible or non-combustible source (such as electricity). In otherembodiments, the energy is provided by a combustion reaction using acombustible material and atmospheric air.

In some embodiments, the driver gas is a hydrogen-rich gas mixture. Inother embodiments, the driver gas is a carbon dioxide rich gas mixture.In yet other embodiments, the driver gas is a mixture of hydrogen andcarbon dioxide gas, in various proportions.

In some embodiments, the reformer module includes a catalyst in thereforming reaction chamber. The catalyst reduces the temperaturerequired to reform the fuel source.

Various embodiments of the reformer module are provided herein based oneither separating the reforming reaction from the combustion reaction(referred to herein as indirect reforming module) or based on combiningthe reforming reaction with the combustion reaction (referred to hereinas autothermal reforming module, or direct reforming module). Inaddition, the reformer modules may include heat exchange elements tofacilitate heat transfer from the high temperature driver gas toincoming reformer and/or combustion fuel. The transfer of heatfacilitates the reforming reaction and lowers the energy required tocomplete the driver gas formation. Note that various reformer moduleconfigurations are envisioned to be within the scope of the presentinvention as long as the reformer modules provides for on-site,portable, energy efficient reforming reactions (and preferably steamreforming reactions) that produce driver gas useful in the extraction ofpetroleum products from an underground source. As such, one illustrativeembodiment of an indirect reformer module is described in FIG. 3 forseparate reformer and combustion reactions, followed by an embodiment ofa direct reformer module described in FIG. 4 for autothermal (direct)reforming and production of driver gas from a single reaction chamber.

Indirect Reformer Module

According to an embodiment of the present invention, disclosed herein isan indirect reformer module adapted to generate driver gas for removingoil from an oil well. In one example, the indirect reformer module mayinclude a first storage container for storing a combustible materialused in the combustion reaction; a second storage container for storinga fuel or alternative hydrocarbon source used in the reforming reaction;a third storage container for water to be reacted with fuel in thereformer; a first chamber having an inlet and an outlet, the firstchamber for combusting the combustible material with ambient oxygen forthe release of energy, the inlet of the first chamber fluidly coupledwith the first storage container; and a second chamber having an inletand an outlet, the inlet of the second chamber fluidly coupled with thesecond and third storage containers, a portion of the second chamberpositioned within a portion of the first chamber, the second chamberfluidly isolated from the first chamber. In one example, the energyreleased in the first chamber heats the fuel and water sources used inthe reforming reaction in the second chamber to a temperature above thatnecessary for the reforming reaction, thereby reforming the fuel andwater sources into driver gas exiting the outlet of the second chamber.

In one example, the first chamber includes an igniter for igniting thecombustible material, and the second storage container may include amixture of water with the reforming reaction fuel source. The secondchamber may be adapted to receive a catalyst to reduce the temperatureand amount of energy required to heat the reforming reaction fuel andwater sources to a temperature above that necessary for the reformingreaction to proceed.

In another embodiment, the indirect reformer module may include a firstheat exchange module coupled with the outlet of the first chamber andthermodynamically coupled with the second chamber, the first heatexchange module for pre-heating the reforming reaction fuel and/or watersources. The indirect reformer module may also include a second heatexchange module coupled with the outlet of the second chamber andthermodynamically coupled with the inlet of the second chamber, thesecond heat exchange module for pre-heating the reforming reaction fueland or water sources and for cooling the generated driver gas.

FIG. 3 illustrates an example of a self-contained, portable indirectreformer module 300 for generating driver gas (shown as arrow 302) forinjection into the ground or an oil well, in accordance with oneembodiment of the present invention.

In FIG. 3, an embodiment of an indirect reformer module may include afirst storage container (not shown) that is fluidly connected to acombustion chamber 304 for burning a combustible material, such as coal,oil, natural gas, an alcohol, an olefin, or other fossil fuel. A secondstorage container (not shown) is also provided, which may include areforming reaction fuel source, such as an alcohol, olefin, paraffin,coal/water slurry, oil, natural gas, and the like or mixtures thereof.If the reformer fuel is an alcohol or other chemical miscible in water,the water may be mixed with the fuel in this container. If the reformerfuel is a hydrocarbon such as a paraffin not miscible in water, anadditional inlet (not shown) is used for the water to be delivered tothe reaction chamber 306.

In one example, a first chamber 304 has an inlet port 308 and an outletport 310 and is adapted to provide for the combustion of the combustiblematerial. In one example, the first chamber 304 includes an igniter suchas a spark plug 312 or other conventional igniter, and a nozzle 314coupled with the inlet port 308 of the first chamber 304. The inlet port308 of the first chamber may be coupled with the first storage container(not shown) so that the contents of the first storage container (notshown) may be introduced into and combusted within the first chamber304. The first chamber 304 also includes a port 316 for introducingcombustion air into the first chamber 304. The first chamber 304 is alsoadapted to receive a portion of the second chamber 306, described below,so that the energy/heat from the combustion of the combustible materialfrom the first storage container (not shown) within the first chamber304 is transferred into a portion of the second chamber 306. The outletport 310 of the first chamber 304, in one example, is near the inletport 320 of the second chamber 306, and a heat exchanger 318 is used toallow the combustion exhaust gas to heat the fuel and water entering thesecond chamber 306. Alternatively, the outlet 310 of the first chambercan feed to a heat exchanger (not shown) located inside the secondchamber 306, which thereby allows the combustion exhaust gases producedin the first chamber 304 to provide the heat to drive the reformingreactions in the second chamber 306.

The second chamber 306 has an inlet port (shown as arrow 320) and anoutlet port 302. In one example, the inlet port 320 is coupled with thesecond storage container (not shown) and receives the contents of thereformer fuel and water storage containers (not shown). The secondchamber 306 may also include a port 322 for receiving catalyst materialwithin the second chamber 306.

In one example, the second chamber 306 is positioned within the firstchamber 304, such that the combustion heat/energy from the first chamber304 heats the reforming reaction fuel and water sources contained withinthe second chamber 306 to a point where the fuel source vaporizes andreforms into a driver gas which exists out of the outlet port 302 of thesecond chamber 306. In one example, the first and second chambers arefluidly isolated. The driver gas exiting the outlet port 302 of thereformer module may be fed into the other modules of the DGGS, includingthe compression module for compression, the injection module forinjection into the oil well, the gas separator module for the separationof hydrogen from the driver gas, the power generator module forgenerating electricity, as well as into other modules.

A catalyst may be utilized within the second chamber 306 of the indirectreformer module in order to reduce the temperature and amount of energyrequired to heat the reforming reaction fuel and water sources to theirreaction temperature and such catalysts are dependent upon the fuelsource but include iron based catalyst, zinc oxide, copper basedcatalyst, alumina, and other catalysts. In some reformer modules, acatalyst may not be required; for example, as described below, in hightemperature steam reforming of coal, a catalyst may not be needed.

In one example of the indirect reformer module, a first heat exchanger318 is coupled with the outlet port 310 of the first chamber 304 (thecombustion chamber) and is thermodynamically coupled with a portion ofthe inlet port 320 of the second chamber 306. In this manner, the hotcombustion exhaust gases from the first chamber 304 are used to preheatthe reforming reaction fuel and/or water sources as they are beingintroduced into the second chamber 306 for vaporization/reformation intoa driver gas.

A second heat exchanger 326 may also be utilized, wherein the secondheat exchanger 326 is thermodynamically coupled with the outlet port 302and the inlet port 320 of the second chamber 306, which provides thedual benefit of preheating the reforming reaction fuel and/or watersources prior to entry into the second chamber 306, as well as coolingthe driver gas which is expelled from the outlet port 302 of the secondchamber 306. Note that various illustrative temperatures are shown toillustrate heat-exchange, but are not meant to limit the range oftemperatures useful in the present invention.

Not withstanding the above examples, the present invention does notrequire the use of heat exchangers. The use of heat exchangers, or aheat exchange module, is optional. Heat exchangers may be used toincrease the efficiency of the reformer module. However, there may besituations in which heat exchangers would not be used, such as when hotdriver gas is desired and/or when the reaction fuel and/or water sourcesare pre-heated.

Autothermal (Direct) Reformer Module

According to another embodiment of the present invention, disclosedherein is an autothermal (direct) reformer module for generating drivergas to remove oil from an oil well. In one example, the autothermalreformer module may include a single reaction chamber for combining areforming fuel source, water, and an oxidizer; a reforming reaction fueldelivery pipe for delivery of the reforming fuel source; anotherdelivery pipe for water; an oxidizing agent delivery pipe for deliveryof oxygen or other oxidizing agent; and a driver gas outlet port forremoval of driver gas produced in the reaction chamber. In one example,a counter-flow heat exchange module transfers energy/heat from thereleased driver gas to the incoming reformer fuel to facilitate theautothermal reformer reaction in the reaction chamber.

In one example of the autothermal reformer module, a reaction chamberheater pre-heats the reaction chamber to initiate the reforming reactionand subsequent formation of driver gas. In another example, the reactionchamber includes a catalyst bed to facilitate autothermal reforming ofappropriate reforming fuel sources.

FIG. 4 illustrates an example of a self-contained, portable autothermalreformer module 400 for generating driver gas for injection into theground or an oil well, in accordance with another embodiment of thepresent invention. The embodiment illustrated in FIG. 4 provides an“autothermal reformer module” for the production of driver gas that isinjected into the ground or an oil well (to remove oil or natural gas orother like materials).

An autothermal reformer module 400 of the present invention directlyreacts a reformer fuel source with oxygen or other oxidizers in a singlechamber 402. Embodiments of the autothermal reformer module provide anenvironment for reforming a fuel source from a feed at propertemperature and pressure resulting in the release of driver gas. Sincethe reforming reaction is favored by low pressure, in some embodiments,pressure in the autothermal reactor is maintained under 50 bar, andpreferably under 1 bar. Some embodiments of the autothermal reformermodule combine counter-flow heat exchange elements to enhance heattransfer and energy efficiency of the autothermal reformer module.

FIG. 4 shows one embodiment of the autothermal reformer module 400 ofthe present invention. Note that other autothermal reformer modules areenvisioned to be within the scope of the present invention as long asthey provide at least a reaction chamber with a reforming reaction fuelsource inlet, an air or oxidizing agent inlet, and a driver gas outlet.

Referring to FIG. 4, an autothermal reformer module 400 is shown havinga reaction chamber 402, a reforming reaction fuel/water delivery pipe(feed pipe) 404 for delivery of a reforming reaction fuel and water, adriver gas outlet port 406 for release of produced driver gas 418, andan oxygen or other oxidizing gas inlet pipe (gas pipe) 408 for deliveryof an oxidizing gas used in the combustion of the reforming reactionfuel in the reaction chamber. In the example shown in FIG. 4, thereformer fuel is methanol, which is miscible in water, and so thefuel/water mixture may be fed into the reaction chamber 402 via a singlefeed pipe 404. This is also a potentially viable arrangement if thereformer feed is coal/water slurry. In alternative embodiments, notshown in FIG. 4, the reformer fuel may be oil or another combustiblematerial not miscible in water. In such cases, separate feed pipes andinlets for the water and fuel may be required.

Still referring to FIG. 4, the reaction chamber 402 is of sufficientsize and shape for autothermal reforming of a fuel source. Differentchamber geometries can be used as long as they constrain the autothermalreforming reactions of the present invention and provide sufficientchamber space to produce an amount of driver gas necessary at an oilextraction site. A catalyst bed 410 (see below) is sometimes integratedinto the reaction chamber for optimized autothermal reforming reactions.In the embodiment shown in FIG. 4, the fuel/water feed pipe 404 iscoupled to the outlet port 406 to form a counter-exchange heat exchanger412 so that the energy/heat from the exiting driver gas 418 istransferred to the reforming feed entering the reaction chamber 402 viathe feed pipe 404. In addition, the feed pipe 404 typically enters at afirst or top end 414 of the reaction chamber and releases the fuel/watermixture toward the second or bottom end 416 of the reaction chamber.This configuration enhances heat release from the heated reformer fuelinto the contents of the reaction chamber 402. Release of fuel and waterinto the chamber 402 can be via a nozzle 416 or other like device. A gaspipe 408 is typically coupled to or adjacent to the feed pipe 404 andreleases the oxygen or other oxidizing gas adjacent to the release ofthe reformer feed 417. Note that other configurations of reformer fueland water delivery, oxygen or other oxidizing agent delivery, and drivergas release are envisioned to be within the scope of the invention andare shown in FIG. 4 as an illustration of merely one embodiment.

When in use, the reaction chamber 402 of the autothermal reformer moduleis typically preheated to a temperature sufficient to start thereforming reaction, i.e., between approximately 200° C.-400° C.Preheating may be accomplished by a reaction chamber integrated heatingelement, a heating coil, an external combustor heating system, aninternal combustion system, or other like device (not shown).

The reformer fuel source (with or without water, see below) is fed intothe reaction chamber 402 via the fuel pipe 404. Note that once drivergas is produced in the reaction chamber 402, the reformer fuel is heatedprior to delivery into the reaction chamber 402 by the exiting drivergas (shown as arrow 418) via the counter-flow heat exchange module 412.At approximately the same time that the reformer fuel is being deliveredto the reaction chamber 402, the oxygen or other oxidizing agent isbeing delivered to the reaction chamber 402 via the inlet pipe 408.Various reformer chemical reactions are described below.

In alternative embodiments, not shown, a second, separate fuel may alsobe fed into the reaction chamber 402. For example, if the primaryreformer feed is coal/water slurry, it may be advantageous to also feedinto reaction chamber 402 a quantity of natural gas or a quantity ofsome other highly combustible material, in order to assure that thereaction chamber 402 remains at high temperature and does not quench.

Once the reforming reaction has been established within the reactionchamber 402, the reaction chamber heating element may be shut off toconserve energy. Note also that the amount of water combined into thereforming fuel can be adjusted to control the reforming temperatures.

Chemical Processes

The generation of driver gas(es) will now be described, for examplegenerating driver gas, i.e., a mixture of hydrogen (H₂), carbon dioxide(CO₂), and possibly other gases. The constituents of driver gas producedby embodiments of the present invention is determined by the reactionconstituents and conditions as described below, but generally mayinclude hydrogen gas, carbon dioxide gas, and mixtures thereof.

Embodiments of the present invention provide processes for producingdriver gas from the reforming of select fuel sources, such as solid,liquid and/or gaseous hydrocarbons, alcohols, olefins, paraffins,ethers, and other like materials. Illustrative fuel sources for use inthe reforming reaction include, but are not limited to, coal, coal/waterslurries, methanol, ethanol, propane, propylene, crude oil, and octane.

The combustor fuel can include both refined commercial products such aspropane, diesel fuel, and/or gasoline, or unrefined substances such ascrude oil, natural gas, coal, or wood. In some embodiments, the drivergas mixture is generated from the steam reforming of clean fuels such asmethanol or ethanol. In other embodiments, the driver gas is generatedby reforming unrefined hydrocarbon sources such as natural gas, coal, orcrude oil, especially crude oil obtained from the oil well site wherethe driver gas is being injected.

In other embodiments, the driver gas is generated by reforming solidhydrocarbons, such as coal, either as solid coal or in the form ofcoal/water slurries. The coal used could be lignite, sub-bituminous,bituminous, anthracite, peat, and the like. The solid hydrocarbons maybe used for the reforming reaction fuel, the combustion reaction fuel,or both. One advantage of utilizing solid hydrocarbons is the relativelow price of coal and other solid hydrocarbons compared to many liquidand gaseous fuels.

The methods of the present invention are reproducible and easilyperformed in the portable and modular systems described herein. Forpurposes of generating hydrogen, the processes of the present inventionare superior to electrolytic hydrogen generation, which require largeamounts of electrical power and are typically non-portable. Theprocesses of the present invention are also superior to the productionof hydrogen by cracking or pyrolysis of hydrocarbons without the use ofwater because much more driver gas is produced for a given amount offuel consumed.

The methods of the present invention use easily obtained fuel sourcessuch as hydrocarbon sources, water, and atmospheric air.

Embodiments of the invention also include combustible materials tosupply the energy to drive the reforming reactions of the presentinvention. Combustible reactions can include a source of fuel that isburned with ambient oxygen for the release of energy. Note that inalternative embodiments of the present invention, the energy used todrive the reforming reactions of the invention may be provided bynon-combustion sources, such as solar, nuclear, wind, grid electricity,or hydroelectric power.

In some embodiments of the present invention, the reforming reaction togenerate driver gas and combustion reactions to drive that reaction bothincorporate the same fuel. For example, methanol may be used as thereforming fuel source and as the source of combustion to drive thereforming reaction. Similarly, Coal, oil, or natural gas may be usedboth as the reforming fuel source and as the source of combustion todrive the reforming reaction. Alternatively, different fuel sources maybe used for the combustion fuel source and the reforming fuel source.

In more detail, the present invention provides reforming processes ofany reforming fuel source to generate, for example, H₂, CO₂, andpossibly other gases. The driver gas reforming reactions of the presentinvention are endothermic, requiring an input of energy to drive thereaction toward fuel reformation.

In one embodiment, the energy required to drive the reforming reactionis provided through the combustion of any combustible material, forexample an alcohol, a refined petroleum product, crude petroleum,natural gas, wood, or coal that provides the necessary heat to drive theendothermic steam reforming reaction.

In other embodiments, the energy required to drive the reformingreaction is provided via any non-combustible source sufficient togenerate enough heat to drive the reforming reaction to substantialcompletion. Examples of non-combustible sources include solar, nuclear,wind, grid electricity, or hydroelectric power.

The present combination of reforming and combustion reactions can beperformed within a portable reforming module, for example the modulesdescribed above (see FIG. 3 and FIG. 4). This is in contrast toelectrolytic hydrogen gas formation, which requires large amounts ofelectrical power and non-portable machinery for the generation of gas.

The following reactions provide illustrative processes for reforming afuel source to produce a driver gas used in the recovery of oil or otherlike materials. Several illustrative combustion reactions that providethe energy required to drive those reforming reactions are alsoprovided. In one embodiment, shown in Reaction 1, a hydrogen and carbondioxide rich driver gas is formed using pure methanol. Note that thereforming reaction and combustion reaction can be performed in separatereaction chambers (see FIG. 3) or can be combined and performed in asingle reaction chamber (see FIG. 4). The following 12 reactionsillustrate a separation of the reforming and combustion reactions,however, as shown in FIG. 4 and discussed in greater detail below, anautothermal reforming reaction can be accomplished by directly reactingthe fuel sources of the present invention with oxygen in a singlereaction chamber. Importantly, these autothermal reactions may beperformed in the presence or absence of water.

Separate chamber reactions (see FIG. 3):

Reaction 1 comes with an ΔH of +128.6 kJoules/mole. This means that thissame amount of energy should be contributed by the combustion reactionto drive the reaction toward the formation of CO and H₂.

In an alternative embodiment, the reformed fuel, e.g., methanol, can bemixed with water as shown in reaction 2:

Reaction 2 comes with an ΔH of +131.4 kJoules/mole. As shown above inReactions 1 and 2, for a small price in energy, an appropriate fuelsource can be cracked to form hydrogen, carbon monoxide, and carbondioxide. By comparing Reaction 2 to Reaction 1, observe that foressentially the same energy, the use of water allows the hydrogen yieldto be increased by 50%. This is why it is generally advantageous toemploy both water and fuel in the proposed reforming reactions.

Reactions 3-9 illustrate several other reforming reactions that are inaccordance with the present invention.

Note that in general Reactions 1-9 (as well as other reforming reactionsof the present invention) result in large increases in the number ofmolecules of products compared to reactants, so all are benefited bybeing performed under low pressure. An important reaction to note isReaction 9, in which coal is reformed with water to generate carbondioxide and hydrogen gas. This coal reforming reaction will be describedin greater detail below.

In alternative embodiments, the reforming reaction is performed in thepresence of a catalyst, for example, when the reforming reaction fuel isan alcohol, e.g., methanol or ethanol, which is combined with water, thefeed is passed over a copper on alumina, copper on zinc oxide, or othercopper-based catalyst at temperatures above approximately 250° C.(although better results may be obtained at higher temperatures). Thus,for example, the reactor chamber in FIG. 4 could be prepared with acopper on zinc oxide catalyst when the reformer fuel is an alcohol.

When the reforming reaction fuel is a hydrocarbon, e.g., paraffins,olefins, aromatics, combined with water, the feed is passed over an ironbased catalyst at temperatures above approximately 300° C. (althoughbetter results may be obtained at higher temperatures).

When the reforming reaction fuel is methane combined with water, thefeed is passed over a nickel or ruthenium based catalyst at temperaturesabove approximately 400° C. (although better results may be obtained athigher temperatures).

In some embodiments, such as when the reforming reaction fuel is coal ora derivative of coal, and/or when high temperatures are used in thereforming reaction, no catalyst is necessary, as discussed below inrelation to the coal modules.

In some embodiments, combinations of olefins, paraffins, and aromatics(as found in crude petroleum) can be used as the reforming reaction fuelsource. In other embodiments, a crude petroleum product is used as thereforming reaction fuel source where the crude petroleum product isfirst treated to remove sulfur or other impurities (sulfur can poisoncatalyst involved with the reforming reaction). Note that otherreforming reaction fuel sources may also be pre-treated for removal orsulfur or other impurities, for example, natural gas. Sulfur removal isdescribed in greater detail below.

In another embodiment of the present invention, a reforming reactionfuel source can be generated from a pre-source. In one example, gammaalumina is used to react dimethyl ether with water to make methanol viaReaction 10:

The methanol produced in Reaction 10 can then be reacted with more watervia Reaction 2 to produce the driver gas used to obtain oil fromdepleted oil wells, for example. As such, using a mixed gamma aluminaand copper catalyst bed, dimethyl ether and water are reacted to obtainthe net result shown in Reaction 11:

The energy used to drive the reforming reactions is provided by eithercombustible or non-combustible sources. In some reactions, the energy isprovided by combustion of a combustible material and in some embodimentsthe combustible material is the same as the reforming reaction fuelsource.

An illustrative combustion reaction is shown in Reaction 12. Thecombustion of a source of fuel supplies the energy to drive reactions1-11. An illustrative example is the combustion of methanol with ambientoxygen to release ΔH of −725.7 kJoules/mole:

Thus, theoretically (not being bound by any particular theory), forpurposes of this illustration, only ⅕ of the mass of methanol isrequired to be burned to reform methanol via Reactions 1 and/or Reaction2. This is a small price to pay given that most fuels used in thereforming reaction are cheap, easy to store as a liquid or solid andreadily available, even in remote areas of the world.

Alternatively, in another embodiment, solid hydrocarbons (such as coal),may be burned/combusted to generate the energy required to drive thereforming reactions 1-11, as shown in Reaction 13 (releasing ΔH =−92kcal/mole):

An advantage of using coal, a derivative of coal, or other solidhydrocarbons is the relative inexpense of coal as compared to liquid orgaseous fuels.

In general, the required energy to drive the reforming reactions of thepresent invention may be furnished by burning small fractions of thereforming reaction fuel source or by using an alternative fuel or otherheating methods such as nuclear, solar or electric grid power. In eachcase, a much larger number of product molecules is produced than isburned or reacted, allowing a much larger amount of fuel to be drivenout of the ground than must be used to obtain it. The driver gasconsists of mixtures of hydrogen and carbon dioxide, neither of whichwill react with petroleum, and both of which can serve to reduce itsviscosity and provide pressure to drive the petroleum from the ground.

In yet another embodiment, carbon monoxide derived from variousreforming reactions is separated from the hydrogen gas using a membraneor other separation device and further burned to provide additionalenergy to drive the reforming reaction, as shown in Reaction 14.

The burning of CO results in an ΔH of −283.0 kJoules/mole, againreleasing heat for use in driving the reforming reactions illustrated inReactions 1-11, as well as generating addition CO₂.

With regard to autothermal reforming, a reforming fuel is directlyreacted with oxygen in the presence or absence of water. In alternativeembodiments, to facilitate combustion of all of the reforming fuel,oxygen gas, air, or alternative oxidizer materials, e.g., hydrogenperoxide, or nitrous oxide, is metered in an amount to react with all ofthe carbon contained in the reforming fuel. The thermodynamics of theautothermal chemical reactions and the presence of a proper catalystwith proper selection of operating temperature and pressure result information of substantially only carbon dioxide and hydrogen gas.However, in use, small amounts of water and other compounds may form bycombustion of hydrogen or other byproduct reactions. Where air is usedas the oxidizer, there will also be nitrogen left over which can serveas part of the driver gas.

Coal Reformer Modules

In one embodiment of the present invention, a coal reformer module,which is capable of reacting coal with water to generate the driver gas,is used as the fuel reformer module. A significant advantage ofutilizing a coal reformer module is the extreme low cost of coal inrelation to liquid or gaseous fuels. A potential disadvantage is thehigher storage, transport, handling, and processing costs associatedwith utilizing coal. The coal reformer module may be especiallyadvantageous in locations where coal is readily and/or cheaply availableat or near the site of the oil well, as is often the case at many oilfields. The main advantage of the modular aspect of the presentinvention is an operator's ability to customize and optimize the DGGS tolocal and changing conditions. Therefore, an operator may use a coalmodule at a location where coal is readily available, but may use amethane module where methane is readily available.

As shown by Reaction 9, coal may be used as the hydrocarbon feed forsteam reforming to generate carbon dioxide and hydrogen driver gas. Coalmolecules contain carbon and hydrogen with varying amounts of sulfur,nitrogen, and oxygen. Coal also contains variable amounts of moistureand inorganic mineral matter (a mixture of silicon, aluminum, calcium,magnesium iron, sodium, potassium, and other oxides plus iron sulfides).To utilize coal as a feedstock material, some additional processingsteps are added to the process described above to handle solid feeds andthe presence of sulfur contaminants. Alternatively, coal may be powderedand mixed with water to form a slurry, which may be handled by thesystems of the present invention as a liquid feed.

Coal is generally the lowest-cost steam reforming feedstock. Forexample, coal may be obtained at a typical cost of $30 per ton(approximately 3 cents per kilogram), and coal with a high water-content(which is usable in this application since water is also a reactant) maybe obtained at a significantly lower cost.

As used herein, the term “coal” may include any solid hydrocarbon, andderivatives thereof, including but not limited to lignite,sub-bituminous, bituminous, anthracite, peat, and the like. The term“coal” is also intended to include derivatives of coal, including butnot limited to coal of all particulate sizes, crushed coal, pulverizedcoal, coal/water slurries, liquefied coal, etc.

For utility power generation, coal is usually prepared and shipped asapproximately 2-inch top-size product. However, many coal producers shipcoal of other particle sizes for industrial boilers, metal casting, andother applications. For driver gas applications, coal of approximately1-inch or smaller top size is preferable as feed to the reformer module.Alternatively, coal may be powdered and mixed with water to form aslurry, which may be handled by the reformer system as a liquid feed.

The present invention provides for at least three possible coal-steamreforming modules, but is not limited to the three coal reformer modulesdescribed here. These include the fixed-bed reformer module (FIG. 5),the fluidized-bed reformer module (FIG. 6), and the entrained-flowreformer module (not illustrated). The coal reformer modules increase incomplexity in the order listed. The solid residue handling requirementsalso increase in complexity in the same order. However, reaction ratesalso increase in the same order, leading to reduced equipment sizes fora given throughput. Each coal-steam reformer module may be implementedas an indirect reformer configuration (as shown in FIG. 3), or as anautothermal reformer configuration (as shown in FIG. 4).

Table 1 shows important features that distinguish the three possiblecoal-steam reformer modules. Values are shown to illustrate relativedifferences in the module parameters.

TABLE 1 Operating parameters of various coal-steam reformer modulesFixed-Bed Fluidized-Bed Entrained-Flow Operating Reformer ReformerReformer Parameter (FIG. 5) (FIG. 6) (not illustrated) Feed ParticleSize approx. <1″ approx. <1/4″ approx. <0.1″ Temperature approx. >700°C. approx. >800° C. approx. >1,200° C. Solids Retention greatestintermediate shortest Time Gas Retention longest shorter shortest Time

All three coal reformer modules operate at sufficient temperature toeliminate catalyst requirements for steam reforming. The fixed-bed andfluidized-bed reformer modules are able to accept coal of the deliveredparticle size. The entrained-flow reformer module would requireadditional grinding or pulverizing after delivery of the coal to the oilsite and before injection into the entrained-flow reformer module.

In one embodiment of the present invention 500, depicted in FIG. 5, aportable self-contained fixed-bed coal reformer module 501 is used togenerate driver gas for injection into the ground of an oil well. In thereaction chamber of the fixed-bed reformer module, nearly all the feedand residue particles remain in reaction chamber 501 during reforming.Delivered coal 502 with a feed particle size of less than approximately1-inch is introduced into hopper 503. The coal 502 is then fed intofixed-bed reformer module 501 through feeder 504. Combustion air oroxygen (shown as arrow 505) and steam (shown as arrow 506) are also fedinto the fixed-bed reformer module 501. In one example, heat recoveredfrom the gas exiting the reformer module 501 is directed into heatrecovery module 507. The heat can be sent to steam generator 510 toconvert water (shown as arrow 508) into steam (shown as arrow 506).Alternatively, the heat can be used to generate electrical or mechanicalpower to drive compressor module 509 or other hardware at the oil site.

The fixed-bed reformer module 501 may be fed and discharged in batchmode, semi-batch mode (incremental feeding and discharging of ash), orcontinuous mode. In the fixed-bed reformer module 501, the inorganicmatter (coarse ash) 514 remaining after steam reforming is largelyhandled in the form of coarser particles that can be removed from thebottom of the reactor chamber. Smaller amounts of ash are entrained inthe low velocity exhaust gas exiting the reformer module. This fine ash510 is removed through bag filter 512. Subsequently, the purified drivergas is pressurized in compressor module 509 to generate pressurizeddriver gas (shown as arrow 511) that is injected into injection well513. The compressor module 509 compresses the driver gas to a pressureappropriate for the oil well, potentially utilizing a feedback pressurecontrol system as described below.

In an alternative embodiment 600 of the present invention, depicted inFIG. 6, a portable fluidized-bed reformer module 601 is used to generatedriver gas for injection into the ground of an oil well. In thefluidized-bed reformer module 601, most particles remain in the reactionchamber, but finer particles are entrained with the exhaust gas. Thatis, compared to the fixed-bed reformer module 501 of FIG. 5, greateramounts of fine particles are entrained in the higher velocity exhaustgas (relative to the exhaust gas generated in the fixed-bed reformermodule) and must be removed prior to compression of the driver gas. Thecoarsest of the entrained particles are removed from the gas stream andcan be recycled to the reactor or discharged as residue. The remainingfinest particles are removed by filtration.

FIG. 6 illustrates an example of a system utilizing the fluidized-bedreformer module 601. Delivered coal 602 with a feed particle size ofless than approximately ¼-inch is introduced into hopper 603. The coalis fed into fluidized-bed reformer module 601 upon opening of the rotaryvalve 604. In the fluidized-bed reformer module 601, combustion air oroxygen (shown as arrow 605) and steam (shown as arrow 606) are also fedinto the fluidized-bed reformer module 601. It is noted that in thefluidized-bed reactor module 601, continuous feeding withsemi-continuous discharge of coarser ash 607 is preferable. Intermediateash 608 in exhaust gas exiting the fluidized-bed reformer module 601 isremoved by cyclone separator 609 (to remove intermediate-sizedparticles) and bag filter 610 (to remove the finest particles of ash611) prior to pressurization of the driver gas in compressor module 612to generate pressurized driver gas 617 that is injected into injectionwell 613. The intermediate-sized particles separated by cyclone 609 canbe recycled to the fluidized-bed reformer module 601 or removed asresidue, depending on the extent of their conversion during reforming.In one embodiment of the fluidized-bed reformer module 601, exhaust gasexisting cyclone 609 enters heat recovery unit 614. The heat can be sentto steam generator 615 to convert water (shown as arrow 616) into steam(shown as arrow 606). Alternatively, heat recovered from the reformermodule 601 can be used to generate mechanical power to drive compressormodule 612 or other hardware at the oil site. The compressor module 612compresses the driver gas to a pressure appropriate for the oil well,potentially utilizing a feedback pressure control system as describedbelow.

In another embodiment of the present invention (not illustrated), aportable, entrained-flow reformer module is used rather than a fixed-bedor fluidized-bed reformer module. In an entrained-flow reformer module,virtually all particles are removed with the exhaust gas steam exitingthe entrained-flow reformer module. The feed particle size using theentrained-flow reformer module is generally less than approximately0.1-inch. Compared to the fixed-bed and fluidized-bed reformer modules,the entrained-flow reformer module would require additional grinding orpulverizing of the coal after delivery to the oil site and beforeinjection into the entrained-flow reformer module. Furthermore, with theentrained-flow reformer module, the entire feed stream is entrained andremoved from the reaction chamber at high velocity. Cyclone andfiltration hardware similar to those of the fluidized-bed reformermodule are used, but removal capacities must be greater.

In all three coal reforming modules described above, the modules operateat sufficient temperature to eliminate catalyst requirements for steamreforming. Generally, the fixed-bed reformer module may operate attemperatures above approximately 700° C., while the fluidized bedreformer module may operate at temperatures above approximately 800° C.The entrained-flow reformer module may operate at temperatures in excessof approximately 1,200° C. These temperature ranges are illustrativeonly, and are not intended to limit the scope of the present invention.All three coal reforming modules may operate over temperature rangesoutside those temperature ranges disclosed here.

The fixed-bed reformer 501 of FIG. 5 and fluidized bed reformer 601 ofFIG. 6 may be designed as illustrated in FIG. 3 or FIG. 4. That is, thesteam reforming of coal can be carried out using an indirect reformer,as in FIG. 3, or a direct (“autothermal”) reformer, as depicted in FIG.4. Indirect reforming requires heat exchange between the heat source(coal combustion, for example) and the reformer. Driver gas producedfrom indirect steam reforming results in a greater hydrogen:carbondioxide ratio than driver gas produced from direct (“autothermal”)reforming. It will be appreciated that the combustible material may becoal, or alternatively may be an alcohol, olefin, natural gas, oil, orother combustible source.

Autothermal reforming eliminates the heat exchange requirement sincepartial combustion is performed in the reforming reaction chamber togenerate heat. Using oxygen for the oxidizer, the autothermal reformerproduct gas is still a mixture of carbon dioxide and hydrogen, but thehydrogen:carbon dioxide ratio is lower than that for indirect reforming.Using air as the oxidizer, the autothermal reformer product gas isdiluted with nitrogen. Both indirect and autothermal reforming using airor oxygen are valid methods for driver gas generation. Specifics of feedcoal quality, capital costs, and driver gas requirements will lead tothe optimum selection for each enhanced oil recovery application.

Three illustrative coal reformer modules have been described and shownhere. However, the present invention is not limited to these three coalreformer modules, and any coal reforming module or apparatus is withinthe scope of the present invention, as long as the module can receivecoal or coal/water slurry and generate driver gas.

Sulfur Removal in Coal Reformer Modules

Because steam reforming of coal is performed without catalyst, reformingcatalyst poisoning by sulfur compounds is not an issue. In cases where alow-sulfur coal feed is used, sulfur clean up of the exhaust gas may notbe required at all. In the event of potential issues with corrosioncaused by sulfur-containing gases in combination with any residualmoisture, several sulfur treatment and removal methods are possible.These may be implemented as modular components that may be brought tothe oil site and attached to the coal reformer module. Alternatively,the sulfur removal components may be integrated directly into the coalreformer module.

Dry sorbents may be used to capture sulfur in the exhaust gas. Calciumoxide, magnesium oxide, and sodium carbonate are examples of drysorbents that are capable of trapping sulfur gases in solid form (assulfates or sulfites, depending on the relative oxidation conditions).When the operating temperature and pressure permit effective sulfurcapture, dry sorbent can be added in a coarse form with the coal feed tofixed- or fluidized-bed reformer modules. The resultingsulfur-containing product can then be removed from the reactor chamberwith the ash remaining after reforming. Alternatively, a finer sorbentcan be injected into the gas down stream of the reactor. Sulfurcontaining solids can then be collected in the cyclone or bag filter.For the entrained-flow reformer module, a sorbent will likely performbetter by injection into partially cooled gas down stream of thereactor.

In large-capacity systems, a dry sorbent may be injected in a separateunit down stream of the final ash particulate filter. The sulfur productcan then be collected separately in another filter and can potentiallybe sold as a product.

Sulfur may also be removed by using a wet scrubber module. Wet scrubberscan be configured in venturi, packed-column, or tray-type systems inwhich the cooled gases are contacted with a scrubbing solution orslurry. The resulting scrubber solution or slurry must then be disposed.

In all reformer embodiments, the hydrogen and carbon dioxide driver gasmay be sent into the well for the purpose of oil retrieval, oralternatively, part or all of the hydrogen product may be separated andsent to a generator to produce electric power, or used for hydrogenationof oil in petrochemical processing, or for other purposes.

Methane Reformer Module

In another embodiment of the present invention, a methane reformermodule, which is capable of reforming methane (CH₄, the majorconstituent of, and sometimes referred to as, natural gas) to generatethe driver gas, is used as the reformer module. A potential advantage ofmethane, despite its higher cost relative to coal, is the relative easewith which methane may be handled as compared to coal. The onlypre-processing step associated with methane is the removal of possiblesulfur contaminants. No bulk handling of solid hydrocarbons or theassociated transport and processing steps are required. The methanereformer module is an even more attractive choice in locations wheremethane is readily and cheaply available at or near the site of an oilwell, as is often the case. The cost of methane at an oil well may besignificantly below its market price to the consumer. This is becausemethane is often produced from the same field, or even the same well, asthe oil. Therefore, there would be no transportation or consumer-endprocessing costs associated with utilizing the locally available methanein a methane reformer module. Furthermore, in many remote oil extractionlocations (such as parts of South America and off-shore locations), itis extremely difficult and costly to transport methane to the end-user(since methane is a gas at ambient conditions), and therefore themethane recovered with the oil is often considered a waste product thatis “flared” or burned. Therefore, at such oil sites, it is extremelyeconomical to utilize the methane in a methane reformer in the systemsof the present invention. Because the present invention is highlymodular and highly portable, an operator working in such remotelocations may easily transport the methane reformer module and othermodules to locations of those oil fields where methane is currentlybeing flared.

The natural gas (methane, CH₄) may be either raw or refined. The naturalgas is fed with steam to a reactor in which an appropriate catalyst ispresent. The catalyst is used to maintain selectivity toward the desiredcarbon dioxide and hydrogen products. Like the methanol or coalreformers, the natural gas reformer may be constructed as an indirect orautothermal reformer with the same considerations cited above.

FIG. 7 shows a schematic of a system 700 utilizing a methane reformermodule 703. Natural gas (methane) 701, either from off-site or on-site,is fed via a line into sulfur removal module 702. Desulfurized naturalgas is fed via another line into methane reformer module 703. Steam 704is added to methane reformer module 703. The exhaust driver gas exitingthe methane reformer module 703 is passed through a heat recovery module705, which could be a set of heat exchangers, in which a portion of theheat 706 is recycled back into the methane reformer module 703. Thecooled driver gas is passed to compressor module 707. The compressormodule 707 compresses the driver gas to a pressure appropriate for theoil well, potentially utilizing a feedback pressure control system asdescribed below. Finally, the high pressure driver gas 708 is injectedvia an injection line into injection well 709. The oil is recoveredusing the same injection well 709 (“Huff-and-Puff”) or anotherproduction well (not shown).

As with the coal reforming modules, heat recovered from the natural gasreformer module may be used to generate electrical or mechanical powerto drive the compressor module or other system hardware. Additional andpotentially much greater amounts of power may also be produced bysplitting part of the hydrogen product from the driver gas stream andusing it to generate power in a gas turbine, fuel cell, internalcombustion engine, or other power generation system.

If refined, desulfurized natural gas is used, no gas clean up isrequired. That is, the sulfur removal module 702 in FIG. 7 is not neededand may be removed. If raw natural gas is used, sulfur must generally beremoved before the reformer module 703 to prevent catalyst poisoning.Sulfur contained in natural gas can be removed on catalysts or sorbentssuch as zinc oxide, activated carbon (with chromium or copper), nickeloxide, or certain molecular sieves (13×). Some of these sorbents work atambient temperature; others require elevated temperatures.

Once captured, the sorbents may be disposed or regenerated. Many of thesorbents release trapped sulfur as hydrogen sulfide gas. If desired, thereleased hydrogen sulfide can be collected as elemental sulfur usingmethods such as the Claus process. In the Claus process, a portion ofthe H₂S is reacted with oxygen to form SO₂. The SO₂ then reacts with theremaining H₂S to form elemental sulfur and water. The elemental sulfurmay be recycled or sold to the petrochemical industry for additionalrevenue.

Local Oil Reformer Module

In yet another embodiment of the present invention, a portion of thelocal oil may be used as the fuel source for the reforming reaction.This is highly convenient, and under some conditions may be highlyeconomical. Local, unrefined oil may be significantly cheaper than oilfor the end-consumer because no transportation or processing isrequired. Accordingly, in one embodiment of the present invention, anoil reformer module is used, in which a portion of the oil extractedfrom the oil well is used in a closed-loop system as a reforming fuelsource.

FIG. 8 shows a schematic of a system 800 utilizing an oil reformermodule 804. A portion of the petroleum (oil) 801 recovered from the oilsite is fed via line 802 into sulfur removal module 803. Desulfurizedpetroleum is fed via another line into oil reformer module 804. Steam805 is added to oil reformer module 804. The exhaust driver gas exitingthe oil reformer module 804 is passed through a heat recovery module806, which could be a set of heat exchangers, in which a portion of theheat 807 is recycled back into the oil reformer module 804. The cooleddriver gas is passed to compressor module 808. The compressor module 808compresses the driver gas to a pressure appropriate for the oil well,potentially utilizing a feedback pressure control system as describedbelow. Finally, the high pressure driver gas 809 is injected via aninjection line into injection well 810. The oil is recovered using thesame injection well 810 (“Huff-and-Puff”) or another production well811. A portion of the recovered oil is fed via line 802 back into sulfurremoval module 803, therefore completing the closed-loop system. A smallportion of the oil recovered is reformed, or sacrificed, in order toextract a significant amount of oil from the oil well.

When using locally produced crude oil in the reformer module, as whenusing coal or natural gas, sulfur removal may be necessary, and may beeffectuated in a similar manner.

Gas Separator Module

According to the present invention, a portable, highly economic CO₂ andH₂ generation system is provided which enables enhanced oil recovery tobe conducted wherever the candidate oilfield may be. The DGGS produceslarge quantities of both carbon dioxide and hydrogen gas. The CO₂ may beinjected into an oil well for enhanced oil recovery. The hydrogen gasmay be used to enhance underground oil recovery in a similar fashion toCO₂ (as described above), or alternatively split off from the CO₂product to be used for other purposes, including power generation or thehydrogenation of oil in petrochemical processes.

Hydrogen gas may be mixed with the carbon dioxide gas and injected intothe oil well. Alternatively, the hydrogen may be separated from thecarbon dioxide. The hydrogen gas may be injected into the oil well,followed by injecting carbon dioxide gas. Alternatively, the carbondioxide gas may be injected first, followed by injecting the hydrogengas.

The hydrogen gas may be sold to the petrochemical industry forhydrogenation or other purposes. If hydrogen becomes a popularclean-burning fuel in the future, the hydrogen may be sold for otherpurposes, such as to the transportation industry for hydrogen-electriccars. Alternatively, the hydrogen may be used for electrical powergeneration. For example, the hydrogen may be burned, using for example agas turbine, to generate electricity. The electricity may be used toprovide power for various operations of the oil site. Alternatively, theelectricity may be sold to utility companies by feeding the electricityinto the electric grid.

In order to support any of the above operations, a means to separate atleast a portion of the hydrogen gas from the rest of the driver gas isneeded. The gas separator module is used to separate the hydrogen gasfrom the carbon dioxide gas (as well as the rest of the driver gas). Thegas separator module gives an operator of the present invention a choiceof how much hydrogen to send underground with the CO₂, and how much toretain for surface utilization. Various methods may be used to separatehydrogen gas from carbon dioxide gas. Candidate separator modules usemembranes, Pressure Swing Absorption (PSA), regenerable sorption beds,scrubbing in amine solution, CO₂ freezers, or centrifugal separation.

One class of embodiments of the hydrogen-carbon dioxide separationmodule use membranes. Membranes separate molecules based on theirrelative permeability through various materials that may includepolymers, metals, and metal oxides. The membranes are fed at elevatedpressure. The permeate is collected at lower pressure while theretentate is collected at a pressure close to the feed pressure.

One embodiment of the membrane separation module, which may operate inconjunction with reactions at elevated temperature, utilizes a palladiummembrane. The palladium membrane, which may be fabricated usingpalladium alone or in combination with modifiers, only allows hydrogento permeate. This type of membrane, when operated in a catalyticreactor, such as in a reformer module, enhances yield by removing areaction product from the reaction zone. Some variants of the palladiummembrane are capable of operation at up to 900° C.

Another embodiment of the membrane separation module utilizes ahigh-temperature polymer membrane. This type of membrane is directedtoward CO₂ separation and recovery. A polymeric-metal membrane of thistype can operate at up to 370° C. (versus typical maximum polymermembrane temperatures of about 150° C.), thus potentially improvingprocess energy efficiency by eliminating a pre-cooling step.

Another class of embodiments of the hydrogen-carbon dioxide separationmodule use pressure swing adsorption (PSA). PSA separates carbon dioxideby adsorption onto molecular sieves or hydrotalcite at elevatedpressure. Hydrogen does not absorb and is therefore collected at highconcentration at the outlet. A PSA module contains at least two sorbentcolumns so that while one is in absorption mode, the other one is indesorption mode. Reducing pressure and/or heating desorbs the carbondioxide collected on the column. The PSA module may be designed toproduce nearly pure hydrogen while collecting CO₂, CO, CH₄, and othergases in a separate stream.

Yet another class of embodiments of the hydrogen-carbon dioxideseparation module use regenerable sorption beds. One example of alow-cost regenerable sorbent is sodium carbonate. The sodium carbonatesorbent absorbs at about 60° C. and regenerating at about 120° C.

Another example of a regenerable sorbent is detailed in U.S. Pat. No.7,056,482 to Hakka et al. The regenerable sorbent includes at least onetertiary amine absorbent having a pKa for the amino function from about6.5 to about 9 in the presence of an oxidation inhibitor to obtain a CO₂rich stream. The CO₂ rich stream is treated to obtain the regeneratedabsorbent and a CO₂ rich product stream.

Another example of a regenerable sorbent is described in U.S. Pat. No.7,067,456 to Fan et al. The reaction-based process described thereselectively removes carbon dioxide from a multi-component gas mixture toprovide a gaseous stream depleted in CO₂. Carbon dioxide is separatedfrom a mixture of gases (such as driver gas) by its reaction with metaloxides (such as calcium oxide). This process includes contacting a CO₂laden gas with calcium oxide (CaO) in a reactor such that CaO capturesthe CO₂ by the formation of calcium carbonate (CaCO₃). Once “spent,”CaCO₃ is regenerated by its calcination, leading to the formation offresh CaO sorbent and the evolution of a concentrated stream of CO₂. The“regenerated” CaO is then recycled for the further capture of more CO₂.

In general, processes that generate high CO₂ concentrations are moreamenable to affordable gas separation. Elimination of diluents such asnitrogen from air improves CO₂ capture efficiency greatly. In addition,processes that produce CO₂ at elevated pressure are at an advantage forthe pressure-based separation techniques.

Various gas separator modules may be used, and the present invention isnot limited to the particular gas separators shown or described herein,so long as the gas separators perform at least the function ofseparating hydrogen from the rest of the driver gas.

Compressor and Injection Modules

In many oil wells, the driver gas must be compressed to high pressurebefore it may be injected into the oil well. This is due to the factthat the oil well may already be at a high pressure from methane andother gases in solution as well as previous driver gas injection. Inaddition, pressure generally increases with depth underground. Thecompressor module is used to compress the driver gas to a pressureappropriate for oil recovery. The compressor module is capable ofcompressing the CO₂ as well as a portion of the hydrogen intended forunderground use to high pressure.

Various types of gas compressor modules may be used to compress thedriver gas before injection into the oil well. Numerous types ofcompressors are available, but all are stand alone modules built for theflow, pressure, and temperature design parameters of the DGGS. Thesemodules may be built to operate using electric motors to provide theproper rotation speed and power input. However, air-driven motors orinternal combustion engines may also be used. Alternate drives such asmechanical linkage to the power generator module are also possible, asdescribed below.

Compressors for CO₂, H₂, or a combination of these gases may be based onlubricated or non-lubricated rotary, centrifugal, or reciprocatingdesigns. These types of compressors may use seals around the rotary orreciprocating shafts.

Another class of compressors that may be used to compress driver gas isbased on metal diaphragms. These are available from differentmanufacturers for a wide range of flow rate and pressure requirements.This class of compressors is designed so that no lubricant or coolantcomes in contact with the process gas. Only the metal diaphragm andelastomer seals contact the process gas.

The compressor may be effectively explosion proof. This can beaccomplished by using an explosion-proof pump, or alternatively byhousing a pump that is not rated explosion-proof within an air-tightcontainer that provides an inert environment.

Designs of compressors may be found in U.S. Pat. No. 6,431,840 toMashimo et al., U.S. Pat. No. 5,769,610 to Paul et al., U.S. Pat. No.5,674,053 to Paul et al., and U.S. Pat. No. 5,033,940 to Baumann.

Various compressors are within the scope of the present invention, andare not limited to the designs and configurations illustrated anddescribed here, so long as the compressors can compress the driver gasto a pressure appropriate for injection into the oil well.

The injection module is used to eject the driver gas from the DGGS intoan injection line, while the injection line is used to send the drivergas deep into the oil well for use in oil extraction. The injectionmodule may be a port, a hole, or interlocking mechanism for connectingthe compressor module to the injection line. The injection line feedsthe driver gas down the injection well. Various injection modules andinjection lines are within the scope of the present invention, and arenot limited to the specific designs and configurations illustrated anddescribed here.

Power Generator Module

The hydrogen gas separated by the gas separator module may be used togenerate power. The power may be used on-site to provide power tovarious sub-systems, or modules, or alternatively the power may be soldfor additional revenue. The power generator module utilizes a portion ofthe hydrogen gas separated by the gas separator module to generatepower. In one embodiment, the power generator module is used to generateelectricity. In another embodiment, the power generator module is usedto generate mechanical power for the compressor module. In oneembodiment, the electricity is sold to a utility company by feeding theelectricity into the electric grid. The power generator module may be acombustion turbine, a steam turbine, a fuel cell, or any otherapparatus, system, or module that can generate power (electrical ormechanical or other) from hydrogen gas.

According to one embodiment of the power generator module utilizing acombustion turbine, hydrogen is fed with air to generate power through arotating shaft. Designs of hydrogen gas turbine plants are described inU.S. Pat. No. 5,755,089 to Vanselow, U.S. Pat. No. 5,687,559 to Sato,and U.S. Pat. No. 5,590,518 to Janes. Designs of hydrogen internalcombustion engines are described in U.S. Pat. No. 7,089,907 to Shinagawaet al., U.S. Pat. No. 4,508,064 to Watanabe, and U.S. Pat. No. 3,918,263to Swingle.

Another embodiment of the power generator module uses a steam turbine. Avariety of fuels may be used, including a portion of the separatedhydrogen, part of the coal or other feedstock material, or even wastehydrocarbon gases. The fuel is burned in air in a combustion chamber togenerate heat. The heat is transferred to a closed-loop steam/watersystem through a series of heat exchangers designed to recover thecombustion heat. The high-pressure steam drives a turbine for powergeneration. In one embodiment, the combustion turbine and steam turbinemay be integrated to boost efficiency.

The combustion and steam turbine shafts may be connected to generatorsto produce electrical power. However, they may also be used to producemechanical power from the turbine shaft (for direct drive of the gascompressor module, for example).

As an alternative to combustion, in one embodiment of the presentinvention, a fuel cell module may be used to convert hydrogen directlyto electricity, usually with greater efficiency albeit at a highercapital cost. The fuel cell module, an electrochemical energy conversiondevice, produces electricity from the hydrogen fuel (on the anode side)and oxidant (on the cathode side). The hydrogen and oxidant (which maybe ambient oxygen) react in the presence of an electrolyte. Thereactants (hydrogen and oxygen) flow in and reaction products (water)flow out, while the electrolyte remains in the cell. The fuel cell canoperate virtually continuously as long as the necessary flows ofhydrogen and oxidant are maintained. Designs of fuel cell plants aredescribed in U.S. Pat. No. 6,893,755 to Leboe, U.S. Pat. No. 6,653,005to Muradov, U.S. Pat. No. 6,503,649 to Czajkowski et al., U.S. Pat. No.6,458,478 to Wang et al., U.S. Pat. No. 5,079,103 to Schramm, U.S. Pat.No. 4,659,634 to Struthers, and U.S. Pat. No. 4,622,275 to Noguchi etal.

Various power generator modules are within the scope of the presentinvention, and are not limited to the particular power generators shownor described here, so long as the power generators can generate power,whether electrical, mechanical, or other, from hydrogen gas.

Control Module

A control module is used to control the operation of the DGGS bothautomatically and based on user-input. The control module may usesubsurface data to automatically regulate the operation of the systemvia feedback control. This allows the DGGS to operate with minimal humansupervision or labor. The control module also provides an interface foran operator to control, maintain, and supervise the operation of theDGGS.

The subsurface data used to control the DGGS may include total pressure,partial pressure of carbon dioxide, partial pressure of hydrogen, oilflow rate, gas flow rate, underground temperature, and/or viscosity ofthe oil. A pressure measurement probe leading down the injection linemay measure the total underground pressure. Similarly, the undergroundpartial pressure of the carbon dioxide gas and the partial pressure ofthe hydrogen gas may be measured by a carbon dioxide/hydrogen pressureprobe leading down the injection line. The control module can controlthe system based on the total measured pressure, as well as the measuredpartial pressures of hydrogen and/or carbon dioxide gas.

The oil flow rate may be measured by a flow meter, and the controlmodule may control the system based on the reading from the oil flowmeter. Additionally, the driver gas flow rate may also be measured by asecond flow meter attached to the injection module, and the controlmodule may control the system based on the reading from the driver gasflow meter. The oil flow meter and the driver gas flow meter may alsoserve a secondary purpose of metering the amount of oil extracted andthe amount of driver gas used for system maintenance, optimization, aswell as billing purposes. For example, an operator of the system wholeases the equipment may pay a leasing fee based on the amount of oilextracted or the amount of driver gas generated.

The control module may also measure the underground temperature of theoil using a temperature probe leading down the injection line, andcontrol the system based on the measured underground temperature. Aviscosity probe leading down the injection line may measure theviscosity of the underground oil, and the control module can control thesystem based on the measured underground viscosity of the oil. Thecontrol module may also use other subsurface parameters, or data takenfrom measurement probes, to automatically regulate the operation of thefuel reformer module, the injection module, and the other sub-systems(modules).

In one embodiment, a control method for controlling the DGGS includesthe steps of measuring total pressure inside the oil well, andcontrolling the driver gas output from the DGGS based on the totalpressure. The control method may increase the output from the reformermodule when the measured pressure is below a predetermined threshold,and decrease the output from the reformer module when the measuredpressure is above a predetermined threshold.

In another embodiment, a control method for controlling the DGGSincludes the steps of measuring the partial pressure of hydrogen insidethe oil well, and controlling the injection module based on the measuredpressure. The control method may control the gas separator module toseparate hydrogen gas from the driver gas, and control the injectionmodule to output more hydrogen gas when the measured partial pressure ofhydrogen is below a predetermined threshold, and to output less hydrogengas when the measured partial pressure of hydrogen is above apredetermined threshold.

In yet another embodiment, a control method for controlling the DGGSincludes the steps of measuring the partial pressure of carbon dioxide,and controlling the injection module based on the measured pressure. Thecontrol method may control the gas separator module to separate carbondioxide gas from the driver gas, and control the injection module tooutput more carbon dioxide gas when the measured partial pressure ofcarbon dioxide is below a predetermined threshold, and to output lesscarbon dioxide gas when the measured partial pressure of carbon dioxideis above a predetermined threshold.

In yet another embodiment, a control method for controlling the DGGSincludes the steps of measuring the viscosity of the oil, andcontrolling the injection module based on the measured viscosity. Thecontrol method may control the injection module to output more drivergas when the measured viscosity is below a predetermined threshold andto output less driver gas when the measured viscosity is above apredetermined threshold.

In yet another embodiment, a control method for controlling the DGGSincludes the steps of measuring the flow rate of the oil, andcontrolling the injection module based on the measured oil flow rate.The control method may control the injection module to output moredriver gas when the measured oil flow rate is below a predeterminedthreshold and to output less driver gas when the measured oil flow rateis above a predetermined threshold.

In yet another embodiment, a control method for controlling the DGGSincludes the steps of measuring the gas flow rate of the driver gas, andcontrolling the injection module based on the measured gas flow rate.The control method may control the injection module to output moredriver gas when the measured gas flow rate is below a predeterminedthreshold and to output less driver gas when the measured gas flow rateis above a predetermined threshold.

The above control methods may be implemented as a control system usingnegative feedback for controlling the DGGS to extract oil from an oilwell in an optimal fashion. The control methods may be implemented insoftware, which may be stored on one or more computer-readable storagemedia. The computer-readable media may be used in a general-purposecomputer to control the operation of the DGGS.

The control module may also be used to control the apparatus based oninput from a human operator. The control module may include a set ofcontrols, or a user interface running on an operating system, foruser-driven control of the DGGS. The control module may be remotelyoperated, such as over the Internet or other network, in order to allowincreased flexibility and remote surveillance and monitoring of theoperation of the DGGS. An operator may remotely, automatically, andintelligently control the operation of several different DGGS unitssituated in several different oil wells (which may be situated atseveral different oil fields, which may be spaced hundreds or eventhousands of kilometers apart) from a single control terminal locatedanywhere on the Internet.

For example, the human operator may use the control module to controlthe gas separator module and the power generator module based on thelocal price of electricity. That is, if the local price of electricityhas increased and/or the oil site requires more power, the humanoperator may chose to divert more of the hydrogen to electricitygeneration rather than for use in oil recovery. The opposite conditionmay hold if the local price of electricity dropped or if the marketprice of oil rose; in this case the human operator may divert more ofthe hydrogen gas for enhanced oil recovery. (Alternatively, thisoptimization operation may be performed automatically by the controlmodule based on inputs of the market prices and other parameters.) Thehuman operator may also use the control module to turn the apparatus onor off and as well as perform other day-to-day operations and systemmaintenance.

Various control modules and control methods are within the scope of thepresent invention, and the present invention is not limited to theparticular control modules or control methods shown or described here.In addition, parameters other than the ones described here may be usedto automatically control the DGGS, and all such parameters are withinthe scope of the present invention.

Gas Capture Module

A gas capture module is used to re-capture a portion of the driver gasemerging with the oil and to recycle the driver gas back into the oilwell. The gas capture module allows the CO₂ and hydrogen that isreleased from the oil emerging from the ground to be re-captured andsent via the compressor module and the injection module back undergroundfor reuse. The gas capture module increases the overall efficiency ofthe oil recovery operation, because a portion of the generated drivergas is recycled and reused.

In one embodiment, a gas capture module is created by pumping the oilinto a vessel with a certain amount of ullage space above the oil, anddrawing suction on the ullage with another pump. This operation willlower the vapor pressure of carbon dioxide and hydrogen above the oil,allowing gases in solution to outgas so that they can be recycled backinto the well.

Various gas capture modules are within the scope of the presentinvention, and the present invention is not limited to the particulargas capture modules or methods shown or described here, as long as thegas capture modules or methods are capable of capturing at least aportion of the driver gas emerging with the oil from the oil well.

The Chassis

A chassis is used to support and transport the other sub-systems, ormodules. The chassis may be attached to an appropriate method oftransportation, such as a truck, boat, or aircraft. The chassis,carrying the various modules, may be mounted or carried upon any numberof different vehicles. The chassis may have one or more wheels forsurface transportation, or it may have no wheels and may rely on thewheels of the vehicle on which it is mounted. This configuration makesthe system highly portable, and allows the DGGS to be easily transportedto the location of any oil well, including off-shore and remote wells.

FIG. 9 illustrates an embodiment of the present invention 900 having achassis 902 to support one or more modules. Chassis slots 904, 906, 908,910, and 912 may be used to house a reformer module, a heat exchangemodule, a gas separator module, a power generator module, and/or acompressor module. The chassis may have one or more wheels 913 forsurface transportation, or the chassis may rely on the wheels of thevehicle on which it is mounted. FIG. 9 shows that one or moreinterchangeable modules may be used in each of the chassis slots904-912. For example, any of a number of reformer modules may be used inslot 904. A coal reformer module 914 and a methane reformer module 915are shown for illustrative purposes only. A local oil reformer module, amethanol reformer module, or any other reformer module according to thepresent invention may be used in chassis slot 904. Any heat exchangemodule, such as heat exchanger 916, may be used in slot 906. Any gasseparator module, such as membrane separator module 918 or sorption bed920, may be used in slot 908. Any power generator module, such as gasturbine 922 or fuel cell 924, may be used in slot 910. Any compressormodule, such as compressor 926, may be used in slot 912. Any gasinjection module, such as injection port 928, may be attached to thecompressor module 926. The gas injection module may be a port, a hole,or any interconnecting interface between the compressor module 926 andthe injection line 932. Driver gas 930 exits the compressor module 926via injection module 928 and is sent deep into an oil well via injectionline 932.

The modules are placed on the chassis 902 and interconnected in theappropriate fashion. For example, the heat exchange module 916 isappropriately connected to the reformer module 914 (or 915). The gasseparator module 918 (or 920) takes one feed from the reformer module914 (or 915), and outputs at least two streams of gas, one stream of H₂gas and another stream of CO₂ and other gases. The H₂ stream is fed tothe power generator module 922 (or 924), while the CO₂ and other drivergases are fed to the compressor module 926. Thus, the gas separatormodule 918 (or 920), the power generator module 922 (or 924), and thecompressor module 926 are appropriately interconnected. The injectionmodule 928 and the injection line 932 are appropriately interconnectedwith the compressor module 926.

Some sample chassis designs for surface transportation are described inU.S. Pat. No. 3,614,153 to Tantlinger et al. and U.S. Pat. No. 3,374,010to Crockett et al. Various chassis configurations are possible, and thepresent invention is not limited to the chassis configuration and designillustrated here. For example, a different chassis design andconfiguration may be used for a chassis designed to be carried by anairplane (not shown) and a different design yet may be used for achassis designed to be carried by a boat (not shown).

The Driver Gas Generation System

The operation, inter-connection, and use of the various modules aredescribed in detail throughout this disclosure. These modular componentsmay be mixed and matched by an operator of the present invention inappropriate combinations based on local conditions and market prices.For example, if the oil site has a high power requirement, or the localcost of electricity is high, the H₂ gas may be separated from the CO₂gas using a gas separator as described above, and the H₂ gas may beburned in a gas turbine to generate electricity. The electricity may beused on-site to provide power for the oil field, or sold to an electricdistribution company to generate additional revenue by feeding theelectricity into the electric grid. Therefore, a portable and modularsystem is provided for enhancing oil recovery and generating electricitywherever a candidate oil field may be, including off-shore and remoteoil fields.

FIG. 10 illustrates one example of one embodiment 1000 of the presentinvention for extracting oil from an oil well and for generatingelectricity. This example is illustrative only, and is not intended tolimit the scope of the present invention. A chassis 1002, having twowheels 1004 for surface transportation, supports five modules. Thechassis slots are used to house a coal reformer 1006, a heat exchanger1008, a membrane separator 1010, a gas turbine 1012, and a compressor1014, respectively. An injection port 1016 is attached to the compressor1014. Driver gas 1018 exits the compressor 1014 via the injection port1016 and is sent via injection line 1020 deep into oil well 1022.

A control module 1024 is used to control the operation of each module1006-1016 via bi-directional communication lines (shown as dashedlines). A gas capture module (not shown) may also be used to re-capturea portion of the driver gas that emerges with the oil from the oil well.

The modules are placed on the chassis 1002 and interconnected in theappropriate fashion. The coal reformer 1006 is connected to coal-waterslurry pipe and oxygen pipe (shown as bold arrows) for receiving thereforming reaction fuel and water sources. The heat exchanger 1008 isappropriately connected to the coal reformer 1006. The membraneseparator 1010 takes a feed from the coal reformer 1006 via heatexchanger 1008 and outputs at least two gas streams, one of H₂ gas andanother of CO₂ and other gases. The H₂ stream is fed to the gas turbine1012, while the CO₂ and other driver gases are fed to the compressor1014 (shown as black arrows). Thus, the membrane separator 1010, the gasturbine 1012, and the compressor 1014 are appropriately interconnected.The injection line 1020 is appropriately connected to the compressor1014 via injection port 1016; the injection line 1020 leads deep intothe injection well 1022.

In addition, the gas turbine 1012 may be used to provide power to themembrane separator 1010, as well as the compressor 1014, via electricalor mechanical linkages (shown as white arrows). The gas turbine 1012 mayalso produce surplus electricity, which may be sold for additionalrevenue to a utility company by directly feeding electricity into theelectric grid (shown as arrow 1026).

FIG. 11 illustrates an example of operations for extracting oil from anoil well and generating electricity, in accordance with the embodimentof FIG. 10. Process 1100 begins in step 1102. A portable/modularsystem/apparatus according to the present invention is brought to an oilfield, as shown in step 1104. An existing production well is convertedto an injection well and/or a new injection well is drilled, as shown instep 1106. Driver gas, comprising CO₂, H₂, and/or other gases isgenerated using the portable apparatus, as shown in step 1108. A portionof the H₂ gas is separated from the rest of the driver gas, as shown instep 1110. Using a portion of the separated H₂ gas, electricity isgenerated, as shown in step 1112. A portion of the driver gas intendedfor underground use is compressed to an appropriate pressure, as shownin step 1114.

A portion of the compressed driver gas is injected into the injectionwell, as shown in step 1116. Oil is recovered from the same injectionwell (“Huff-and-Puff”) and/or another production well, as shown in step1118. Optionally, a portion of the driver gas emerging with the oil fromthe oil well is re-captured for reuse underground, as shown in step1120. The process 1100 ends at step 1122.

FIG. 12 illustrates another example of an embodiment 1200 of the presentinvention for extracting oil from an oil well and for generatingelectricity. This example is illustrative only, and is not intended tolimit the scope of the present invention. Fuel 1202 and water 1204 arefed into reformer module 1206. The fuel and water may also be pre-mixedand fed into reformer 1206 as a single stream. Oxygen, or anotheroxidizing agent, are fed into reformer 1206 via another line (notshown). Generated driver gas, which may include CO₂, H₂, as well asother gases, is fed into gas separator 1208, which separates a portionof the hydrogen gas from the other driver gases. A portion of theseparated hydrogen gas is fed into power generator 1210, which could bea gas turbine, to generate electricity. A portion of the electricity isfed into the electric grid 1212. A portion of the electricity may alsobe used on-site, to provide power to various modules, such as thecompressor 1214.

The rest of the driver gas is compressed by compressor 1214 forinjection into injection well 1216. The driver gases, including thecarbon dioxide as well as a portion of the hydrogen gas, and potentiallyother gases (such as N₂), pressurize the underground petroleum formation1218 and reduce its viscosity. Crude oil 1224 is more amenable torecovery by oil recovery head 1222 via production well 1220, or otherlike site.

This is but one system configuration that is possible utilizing themodular components of the present invention, and the present inventionis not limited to this particular configuration. For example, anoperator who does not wish to generate electricity, and/or an operatorwho wishes to use all of the hydrogen gas along with the carbon dioxidegas for enhanced oil recovery, would not use a gas separator module or apower generator module, but would still use a reformer module and acompressor module. As another example, an operator who wishes to operatea hydrogenation plant near the oil well may chose to use a gas separatormodule to separate the hydrogen, but may chose not to use a powergenerator module. Such an operator would still use the other modules,and would feed the hydrogen gas to the hydrogenation plant.

That is, in one embodiment of the present invention, the hydrogen gasmay be separated, and used separately from the carbon dioxide gas. Forexample, the hydrogen gas may be burned in a gas turbine, or sold to thepetrochemical industry for crude oil refinery utilization (notillustrated), or to other parties for other purposes. In an alternativeembodiment of the present invention, the hydrogen may be mixed with thecarbon dioxide, and used in conjunction with the carbon dioxide forenhanced oil recovery.

Additionally, in one embodiment of the present invention, an operator isprovided with multiple fuel reformer modules to choose from. Theoperator would select the appropriate reformer module based on localparameters and detailed economic modeling, as described in detail below.The DGGS may be designed so that the other modules do not need to bereplaced when replacing one reformer module with another reformermodule. The system may be designed to make all modules interchangeableand able to interface appropriately. Examples of the design of thereformer modules are provided above, and may include a methanolreformer, a coal reformer, a methane reformer, a local oil reformer, orany other type of reformer module using any other type of feedstockmaterial. Two examples of reformer modules are illustrated in FIGS. 3and 4. Various reformer modules are within the scope of the presentinvention, so long as the reformer modules generate driver gas from afuel source. The discussion below in relation to FIGS. 13-15 discusses aparametric economic model that could be used for selecting anappropriate fuel reformer module.

Scale of Operations

The scale of the present invention is simultaneously portable and alsosized to generate sufficient driver gas for economic recovery of oil.For example, consider a near-depleted oil well that presently generates1 barrel of oil per day. Established industry guidelines estimate 1additional barrel of oil recovered for every 5,000 to 10,000 standardcubic feet (5-10 kcf) of CO₂ injected into a near-depleted oil well. (Avalue of 10 kcf of CO₂ per barrel of oil recovered will be usedhereafter as a conservative estimate.) Therefore, in order to bring thecapacity of the near-depleted oil well up from 1 Ba/day to 100 Ba/day,the present invention should be sized to generate approximately1,000,000 standard cubic feet (1,000 kcf) of CO₂ per day. That is, inone embodiment of the present invention used for enhanced oil recoveryin an oil field producing 100 barrels per day, an embodiment of thepresent invention would be sized to produce an output of CO₂ gas on theorder of one million cubic feet per day (1 MMcf/day).

However, the present invention is by no means limited to an apparatusthat produces CO₂ at a rate of 1 MMcf/day. For example, if an oil wellis expected to produce 10 Ba/day, an embodiment of the present inventionmay be sized to produce an amount of CO₂ equal to approximately 100,000standard cubic feet (100 kcf) per day. Alternatively, if an oil field isexpected to produce 1,000 Ba/day, an embodiment of the present inventionmay be sized to produce an amount of CO₂ equal to approximately 10million standard cubic feet (10 MMcf) per day. Since the volume of thereaction chamber, and hence the volume of CO₂ produced, grows as thecube of the linear dimension of the reaction chamber, an apparatus thatproduces 10 times the amount of CO₂ would have a linear footprintincrease of approximately 2.2 times (cube-root of 10). That is, anapparatus sized to produce 10 MMcf/day of CO₂ would only be sized abouttwo times larger in each linear dimension than an apparatus designed toproduce 1 MMcf/day of CO₂.

Alternatively, an operator of an oil field may chose to utilize two ormore smaller reformer modules in place of a larger reformer module. Forexample, consider an operator of an oil field described above producing100 Ba/day. Such an operator needs approximately 1 million cubic feet ofCO₂ per day (1 MMcf/day). Instead of utilizing one large fuel reformermodule, an operator may chose to utilize four smaller fuel reformermodules, each sized to produce 250,000 cubic feet of CO₂ per day (250kcf/day). One potential advantage of utilizing four smaller reformermodules over one large reformer module is the ability to space the fourreformer modules easily around a single well. Another potentialadvantage of utilizing multiple smaller reformer modules over one largereformer module is the greater flexibility in transportation of thesmaller reformer modules. Finally, another potential advantage ofutilizing multiple smaller reformer modules is the standardization andeconomies of scale that are possible in manufacturing a reformer moduleof standardized size which is replicated for larger operations.

Therefore, based on the above analysis, it is apparent that an apparatusaccording to the present invention may be produced/manufactured for anyappropriate oil well and/or oil field size at only a small incrementalincrease in production/manufacturing cost. Therefore, the presentinvention is a highly economical, highly portable, and highly modularapparatus that may be customized to an oil well and/or oil field of anysize.

As shown below, the amount of hydrogen produced by reforming sufficientcoal to produce 1 MMcf/day of carbon dioxide gas is also sufficient toproduce about 2 Megawatts (MW) of electric power. This is a convenientsize to feed meaningful amounts of electricity into an electric powergrid to support growth of demand faced by power companies in a modularfashion, without the need for massive investment in new large scale(˜1000 MW) facilities. Thus, the mass production and deployment of fuelreformer modules according to the present invention could be potentiallyvery attractive for power companies, allowing them to meet theircustomer's demand of increased supply, without the risk of majorinvestment in large facilities, while receiving their power from acontinuously-available, carbon-emission-free source. This is in contrastto supplementing utility power with wind turbines or solar cells, whosepower, while also carbon-emission-free, is only available on anirregular, or intermittent, basis.

Various alternative sizes may also be attractive. Therefore, the presentinvention may be sized appropriately, and any mention of particularsizes in this description is illustratively of but a few particularembodiments of the present invention, and is not meant to limit thescope of the present application to any particular size described.

Sample Reformer System Design Calculations

Process embodiments of the present invention can take place as areforming reaction temperature between approximately 200° C. andapproximately 500° C., with better results at higher temperatures,depending on the fuel source and catalyst. As such, the reforming feed,i.e., fuel and water sources, are heated to boiling temperature,vaporized, then continued to be heated to the above temperature range,where they react to form driver gas. After the reforming reaction, thegas product can be cooled. The heat is provided by combustion of a fuelor via a non-combustible source.

With regard to using a combustible reaction to supply the energy todrive the reforming reaction, a spark plug, incandescent wire, or anyother ignition device is typically used to initiate the reaction.

The following description is provided as an illustrative example and isnot meant to limit the description herein. Use of methanol will beprovided for illustrative purposes.

Step 1: Preheat Reformer Feed, Cooling of Gas

The reformer feed (methanol and water) enters the system at 20° C. Theaverage boiling temperature for the CH₃OH and H₂O is approximately 90°C. Assuming as an example a small system with a driver gas productionrate of 100 standard liters per minute, the heat required to preheat thereformer feed from 20° C. to 90° C. is 202 J/s. The heat lost duringthis step is 4 J/s. The aim of this heat exchanger is to have the gasexit at about 35° C. Knowing the preheat will require a total of 206J/s, the inlet temperature of the hydrogen-rich gas needed is calculatedto be 130° C. A heat exchanger model shows that a total length of 2.6 mof tube-in-tube exchanger is needed. When coiled, the resulting heightis about 9 cm.

Step 2: Begin Boiling Reformer Feed, Begin Cooling Gas

The hydrogen-rich gas will be leaving the reaction chamber at about 400°C. As it cools to 130° C., a heat of 613 J/s is produced, 16.5 J/s ofwhich is lost. To vaporize the CH₃OH and H₂O, 1308 J/s is needed.Therefore, the gas partially boils the reformer feed. The total lengthof the tube-in-tube required for this process is 2.1 m. When coiled, theresulting height is about 7 cm. The heat exchangers for Steps 1 and 2may be combined into a single unit.

Step 3: Finish Boiling Reformer Feed, Cool the Combustion Gas

After Step 2, the reforming feed still needs 710 J/s to finishvaporizing, and in this step, 42 J/s is lost. As calculated in Step 5,the combustion gas will leave the reformer at about 648° C. Giving thereforming feed the heat it needs to boil brings the combustion gastemperature down to 127° C. This takes a length of 2.8 m of thetube-in-tube exchanger, which is about 10 cm high when coiled.

Step 4: Finish Heating Reformer Feed

The reforming feed is already vaporized and will finish heating when itcontacts the top plate of a combustion chamber. Heating the reformingfeed from 90° C. to 400° C. requires 518 J/s. This amount of heat bringsthe temperature of the combustion gas from 1650° C. to 1360° C.

Step 5: Reforming Reaction

To reform CH₃OH and H₂O, 1080 J/s of power may be used in this example.This section of the heat exchanger also loses 94 J/s to thesurroundings. Accommodating this, the combustion gas temperature dropsfrom 1360° C. to 648° C. The design length of this multiple tube sectionis about 20 cm.

An equation for determining the heat used or needed for these processesis Q=ΣmC_(p)ΔT. The calculations lead to obtaining the ΔH and heat lostacross a given section and the section's length. The heat exchangeformulas and calculation methods used for the reformer system design aregiven in Incropera and DeWitt (1996).

Economics of Driver Gas Production

The processes of the present invention produce significant quantities ofhydrogen and CO₂. While the yield from CO₂ Enhanced Oil Recovery (EOR)techniques varies depending upon the reservoir in question, it isgenerally taken in the industry that where conditions are appropriatefor the technique, yields of about 1 barrel of oil per 5,000 to 10,000standard cubic feet (5-10 kcf) of gaseous CO₂ can be expected. (For aconservative estimate, the following discussion will assume 1 barrel ofoil recovered per 10 kcf CO₂ injected.) For this reason, CO₂-EOR isgenerally viewed as a viable method to use under conditions where CO₂can be obtained at a cost of $2/kcf or less (e.g., the cost of CO₂ isless than approximately $20/bbl of oil recovered). Unfortunately,currently CO₂ supplies are only available at such costs if the oil fieldin question is situated a comparatively short distance from eithernatural CO₂ reservoirs or large scale artificial CO₂ sources such ascoal-fired power plants, ethanol plants, or steel mills. This situationleaves most oil fields that could otherwise be good candidates forCO₂-EOR stranded out of reach of effective economic recovery.

As recognized by the present inventors, the present invention is amodular, highly portable apparatus/system that may be taken to whereverthe oil site may be. Therefore, the present invention provides CO₂ at aneconomic cost at the oil site. As an example demonstrating the potentialeconomic utility of the present invention, consider the case of acoal-fired unit, whose owner-operator decides to use all of the CO₂product for EOR, while directing all of the hydrogen for another use,for example, power generation. In this example, the owner-operator hasdecided to utilize a solid hydrocarbon, such as coal, for the reformingreaction as well as the combustion reaction because, for example, thecoal is readily and cheaply available, as is often the case at oilsites.

The reforming reaction for coal is shown in Reaction 15:

Reaction 15: C + 2H₂O → CO₂ + 2H₂ ΔH = +40 kcal/mole

This reaction is endothermic, but can be driven by the exothermicburning of coal as shown in Reaction 16:

Reaction 16: C + O₂ → CO₂ ΔH = −92 kcal/mole

Accordingly, four units of Reaction 16 can drive nine units of Reaction15, leaving:

Reaction 17: 13C + 18H₂O + 4O₂ → 13 CO₂ + 18H₂ ΔH = −8 kcal/mole

So, in the nearly energy-neutral Reaction (17), 156 kg of C produce 13kmoles (10.6 kcf) of CO₂ and 18 kmoles (14.7 kcf) of hydrogen.

A typical price for coal is $30/tonne, or $0.03/kg. At this price, the156 kg of C would cost about $4.68. But since this is producing 10.6 kcfof CO₂, the cost in feedstock per kcf of CO₂ produced comes out to$0.44/kcf, well below the approximately $2/kcf industry benchmark foreconomic CO₂-EOR.

However, in addition, the system according to the present invention alsogenerates 18 kmoles (14.7 kcf) of hydrogen. The hydrogen may be usedwith the carbon dioxide in enhanced oil recovery as described above.Alternatively, the hydrogen may be separated from the carbon dioxideusing a gas separator module as noted above and burned to produce power.

Assume the hydrogen gas is burned in a gas turbine to produce power, inaccordance with Reaction 18:

Reaction 18: H₂ + ½ O₂ → H₂O ΔH = −66 kcal/mole

Reaction 17 produces 18 kmoles of hydrogen, which translates to1,188,000 kcal=4,989,600 kJ=1386 kWt-hr of energy. Assuming athermal-to-electrical conversion efficiency of 33%, this transforms to462 kWe-hr. At a typical electricity price of $0.10/kWe, this amount ofpower is worth $46.20. (kWe=kilowatt; kWe-hr=kilowatts per hour.)

Therefore, by using the present invention, an operator transformed $4.68worth of coal into $46.20 worth of electricity plus an amount of CO₂worth $21.20 at the standard EOR acceptable rate of $2/kcf, and whichcan be used to recover 1.06 barrels of oil, worth $63.60 at a typicalexpected oil price of $60/bbl. Taken together, the value of theelectricity plus that of the recovered oil amount to $109.80, or about23.5 times the $4.68 worth of coal consumed in the process.

It should be noted that this is a worst-case scenario for the operationof the present invention, because by being burned for electricity, the18 kmoles of hydrogen yield a lower monetary return than the 13 moles ofCO₂. If the hydrogen can be used with equal effectiveness as CO₂ as ameans of driving oil out of the ground as described above, instead ofproducing $46.20 worth of electricity, the hydrogen would yield $88.06worth of oil, for a total return of $151.66, or 32.4 times the value ofthe coal consumed.

Of course, the operator of the present invention will have other costsbesides coal, including capital equipment, labor, taxes, insurance,etc., but as shown by the analysis below, provided these and othernormal business matters are handled effectively, the potential forprofit from such a system could be quite large.

Profit would be enhanced further if some of the CO₂ and/or H₂ used torecover oil can be recaptured and recycled after the oil is brought tothe surface. Effective use of such techniques would make many fuels muchmore expensive than coal highly attractive for utilization in thepresent invention. Also note that in the above example, power is beingproduced with less emission of CO₂ to the atmosphere. As a result ofwidespread concern over global warming, proposals are being consideredto create taxes on CO₂ emissions, with typical figures mentioned in therange of $50/tonne CO₂ released into the atmosphere. This is equivalentto a tax on coal of $14/tonne, roughly 47% the cost of typical coal. Thepresent invention would allow coal to be burned to produce power withoutincurring such tax penalties.

Considering the figures from the above example, if 156 kg/day of coalproduces 10.6 kcf of CO₂ and 14.7 kcf of hydrogen, then 14,716 kg ofcoal per day will be needed to supply 1 MMcf of CO₂, as well as 1.39MMcf of hydrogen (MMcf=million cubic feet).

Assuming an oil yield of 1 barrel/10 kcf of CO₂, such an operation couldbe expected to recover 100 barrels/day, for a cash value at $60/bbl of$6,000. The hydrogen will yield 43,585 kWe-hr of electricity, for atotal sales value at $0.10/kWe-hr of $4,358/day, and an output powerlevel of 1,816 kWe. At $30/tonne, the cost of the coal to feed theapparatus of the present invention will be just $441/day. (kWe=kilowatt)

Thus, the total gross income generated by the system of the presentinvention would be $10,358/day, or about $3.8 million per year. The coalcosts will be about $160,000 per year. Assuming a payroll of$400,000/year for a five-man operating crew, plus $200,000 per year tomake interest and principal payments on a total plant and equipmentvalued at $2 million, plus another $240,000 per year to cover othercosts, a total overhead budget of $1 million/year is obtained.Therefore, net profit from system operations according to the principlesof the present invention would be about $2.8 million per year.

The above economic analyses show that both hydrogen and carbon dioxidegenerated from coal according to the principles of the present inventionmay be profitably used to extract oil from underground or underwatersources, such as depleted oil wells. As described below, similarcalculations may be used to show that various other fuel sources for thereforming reaction and the combustion reaction may be profitably used toextract oil from depleted oil wells. Similar calculations may also beused to show that the principles of the present invention may be used toextract natural gas from underground or underwater sources, such asdepleted natural gas reservoirs.

According to one embodiment of the present invention, pressurizedhydrogen and CO₂ are injected simultaneously into the oil well. Carbondioxide, when combined with hydrogen, will have a greater impact onenhanced oil recovery than CO₂ or H₂ alone. Carbon dioxide, by virtue ofdissolving in the crude oil, will decrease the viscosity of the oil,making it more readily extractable. By permeating the small nooks andcrevices in the bedrock, the hydrogen will have greater access to theoil and further reduce its viscosity. Thus, carbon dioxide and hydrogenwill have a cooperative and mutually beneficial effect on the oilrecovery process. However, it will be appreciated that this invention isnot limited to this particular theory of operation.

Parametric Economic Analysis: Choosing Between Reformer Modules

A parametric economic model was designed to assist an operator inselecting an appropriate fuel reformer. Certain assumptions are inputinto the model (for example, cost of raw materials and capital/operatingexpenses). The model may be used to select among alternative fuelsources, reformer modules, and among other appropriate modules for theDGGS.

A sample economic analysis was performed to determine the profitabilityof using the DGGS for enhanced oil recovery in a particular oil fieldunder particular market conditions. The results indicate that theoperation of the DGGS system is profitable in this particular scenarioif the system feeds are coal, natural gas, propane, or local oil. Theprofits are directly proportional to the efficacy of H₂ relative to CO₂at recovering oil and inversely proportional to the cost of thefeedstock.

Several assumptions were made about the unit size, the feedstockmaterials, and the capital and operating expenses when utilizing thepresent invention in this particular hypothetical scenario. Anassumption was made on the unit size of the reformer modules. Thecalculations were based on a modular system, with each reformer moduleproducing 250 kcf (thousand cubic feet) of CO₂ per day of operations.Two scenarios were calculated, one in which a single 250 kcf/dayreformer module is used (FIG. 13) and one in which four such reformermodules are used at a single oil site to produce a gross of 1 MMcf/day(FIG. 14).

The feedstocks included in this analysis were coal, local oil, naturalgas, propane, and methanol. For calculation purposes, natural gas wasassumed to be equivalent to methane and local oil was assumed to haveproperties similar to n-decane. The prices and properties of thereforming and combustion reactions are tabulated in Table 2. The priceincludes a $14 delivery charge to the site. This includes 500 miles byrail at 1.4 ¢/ton-mile and 50 miles by truck at 14 ¢/ton-mile (1ton=2200 lbs.) based on data obtained from the United States Departmentof Energy (DOE). Coal was assumed to have an average cost of $44 per ton(a very conservative estimate), local oil was assumed to have an averagevalue of $60/barrel, methane (natural gas) was assumed to have anaverage cost of $6.60/kcf, methanol was assumed to have an average costof $1.65/gallon, and propane was assumed to have an average cost of$1.00/gallon. All pricing data was acquired from the U.S. Department ofEnergy.

Table 2 summarizes the input parameters. Of course, an operator of thepresent invention would adjust these input parameters to fit theappropriate conditions of the oil well that the operator wasconsidering.

TABLE 2 Cost, energy content, and CO₂ and H₂ production quantities ofvarious fuels Combustion per Price Reforming per ton fuel ton fuel $/tonenergy (kJ) cf CO₂ cf H₂ energy (kJ) Cf CO₂ Coal 44.00 14.8E+06 70,666141,332 −32.8E+06 70,666 Local oil 469.00 14.5E+06 58,889 182,556−43.6E+06 69,444 Methane 350.00 15.4E+06 53,000 212,000 −50.1E+06 62,500Methanol 565.00  2.0E+06 26,500  53,000 −19.9E+06 26,500 Propane 544.00 8.4E+06 57,818 192,727 −46.4E+06 57,818

The capital and operating expenses were based on four scenariosdepending on the feedstock and whether the H₂ is injected for oilrecovery or separated for electricity production.

It was assumed that the use of coal would require an additional $500,000in capital expenses for the additional processing steps associated withthe coal reformer modules described above. Furthermore, if the H₂ isseparated and converted into electricity, it was assumed that therewould be an additional $500,000 increase in capital expenses for the gasseparator and power generator modules described above. The capitalexpenses were amortized over a period of 10 years.

The operating expenses were assumed to be slightly higher if coal isused as the feedstock material considering the ancillary equipmentassociated with the coal reformer modules described above. The capitalexpenses and operating expenses are summarized in Table 3.

TABLE 3 Capital and operating expenses for various scenarios H₂ H₂Feedstock injected separated Comment Capital Coal $1,500,000 $2,000,000amortized over Expenses 10 years Capital Other $1,000,000 $1,500,000amortized over Expenses 10 years Operating Coal $300,000 $450,000 peryear Expenses Operating Other $200,000 $300,000 per year Expenses

It was also assumed that each 10 kcf of CO₂ injected would lead to 1 bblof oil recovered. It was also assumed that hydrogen could be convertedto electricity with 33% efficiency and that the electricity could besold for 10¢ per kWe-hr ($0.10/kWh, based on data from the U.S.Department of Energy). It should also be noted that the CO₂ producedfrom the combustion reaction was assumed to be separated from the fluegas and injected into the well for oil recovery.

Using the assumptions above, a cost of operating a 250 kcf/day reformermodule with different operating parameters was calculated. Theperformance was calculated with different combinations of fuels for thereforming reaction and the combustion reaction; whether the hydrogen wasinjected into the well or separated for electricity production; and withdifferent efficacies of hydrogen at oil recovery relative to CO₂. Theresults of this analysis are shown in FIG. 13 for a single day ofoperation at a CO₂ output of 250 kcf/day from the reformer module.Similarly, results were obtained for an oil field operating four suchreformer modules simultaneously to produce 1,000 kcf CO₂ in a single dayof operation, as shown in FIG. 14. (Note that the financial multiplesimprove with the use of four reformer modules.)

Utilizing the calculated results, financial multipliers may bedetermined as a function of the effectiveness of hydrogen at oilrecovery relative to CO₂. This function is shown for different fuels inFIG. 15. It is clear that the profits increase with the effectiveness ofhydrogen relative to CO₂ for all reformer fuels. Notably, even if thehydrogen does not aid in oil recovery, using coal, methane, or local oilis still profitable with financial multipliers ranging from 1.2 forlocal oil to 2.2 for coal.

The results of FIGS. 13-15 indicate that the financial returns areimpressive, especially when a cheap fuel such as coal is used andhydrogen is at least as effective as CO₂ at oil recovery ($4 to $6return on each dollar invested).

Preliminary laboratory test results, which measured only short-termeffects of hydrogen (that is, its physical, not its chemical effects),show hydrogen to be 25% as effective, on a molecule-for-molecule basis,as CO₂ in reducing oil viscosity. This is a significant finding, becauseas shown by Reactions 3-9, significantly more hydrogen is produced on amolar basis than carbon dioxide. If four times as much hydrogen isproduced as carbon dioxide from steam reforming, and hydrogen is 25% aseffective as CO₂, then the total amount of hydrogen is as effective asthe CO₂ in enhanced oil recovery, and the additional hydrogen increasesthe efficiency of CO₂-EOR by two-fold. Further, the preliminary testresults did not take into account the long-term chemical effects ofhydrogen-petroleum interaction (such as in-situ hydrogenation, forexample), nor the potential cooperative effects of hydrogen and carbondioxide.

Thus it may be seen that carbon dioxide and hydrogen, working alone orin combination, have unique properties that can be applied to theproblems of improved recovery of crude oil.

Furthermore, it is anticipated that the demand for DGGS systemsaccording to the present invention would be quite large considering theuntapped oil resources that are available all over the world. CO₂Enhanced Oil Recovery (EOR) is usually only applied in those wells wherethere is an abundant CO₂ supply nearby. This is certainly not the casein, for example, the states of Kansas or Pennsylvania in the U.S., wherethere are hundreds of millions of barrels of oil available that arecurrently out of reach because there is no local source of CO₂,according to the U.S. Department of Energy.

The U.S. Department of Energy estimates that the usage of CO₂ for EORhas the potential to expand the domestic oil supply by 89 billionbarrels of oil (a resource worth $5.3 trillion at current prices). Evenif the DGGS according to the present invention is implemented to recoveronly a small fraction of these resources, the return will be staggering.

While the methods disclosed herein have been described and shown withreference to particular operations performed in a particular order, itwill be understood that these operations may be combined, sub-divided,or re-ordered to form equivalent methods without departing from theteachings of the present invention. Accordingly, unless specificallyindicated herein, the order and grouping of the operations is not alimitation of the present invention.

While the invention has been particularly shown and described withreference to embodiments thereof, it will be understood by those skilledin the art that various other changes in the form and details may bemade without departing from the spirit and scope of the invention.

1. A portable apparatus adapted to extract fluid from a planet'ssubsurface, comprising: a chassis adapted to support a fuel reformer, acompressor, a gas injection unit, a gas capture system, and a controlmodule; the fuel reformer, adapted to react a fuel with water to producea driver gas mixture including at least carbon dioxide gas and hydrogengas; the compressor, adapted to compress a portion of the carbon dioxidegas and a portion of the hydrogen gas; the gas injection unit, adaptedto inject the portion of the carbon dioxide gas and the portion of thehydrogen gas compressed by the compressor into a subsurface reservoir;the gas capture unit, adapted to recapture a portion of the carbondioxide gas and the hydrogen gas, that emerges from the subsurface withthe fluid; the control module adapted to use subsurface data to regulateoperation of the gas injection unit; and a gas injection line,operatively connected to the gas injection unit, and adapted to feed theportion of the carbon dioxide gas and the portion of the hydrogen gas toa predetermined depth within the subsurface reservoir, wherein therecaptured carbon dioxide gas and hydrogen gas are compressed by thecompressor and injected by the gas injection unit back into thesubsurface reservoir.
 2. The apparatus according to claim 1, furthercomprising: a heat exchanger adapted to enhance thermal efficiency ofthe fuel reformer.
 3. The apparatus according to claim 1, furthercomprising: a gas separator, adapted to separate the carbon dioxide gasfrom the hydrogen gas.
 4. The apparatus according to claim 3, furthercomprising: a power generator adapted to utilize a portion of thehydrogen gas separated by the gas separator to generate power.
 5. Theapparatus according to claim 4, wherein the power generator is selectedfrom the group consisting of a gas turbine, an internal combustionengine, and a fuel cell.
 6. The apparatus according to claim 1, whereinthe chassis contains at least one wheel and is operable to be hauled bya vehicle.
 7. The apparatus according to claim 1, wherein the chassis isadapted to be attached to a truck, a train, a water vessel, or anaircraft.
 8. The apparatus according to claim 1, wherein the fuelincludes organic material feedstock.
 9. The apparatus according to claim1, wherein the fuel is selected from the group consisting of coal,coal/water slurries, crude oil, crop, forestry residues, biomass,alcohols, natural gas, refined petroleum products, oil shale, tars,industrial waste products, and mixtures thereof.
 10. The apparatusaccording to claim 1, further comprising: a fuel purification module forpurifying intake coal for use in the fuel reformer.
 11. The apparatusaccording to claim 1, wherein the gas separator is selected from thegroup consisting of sorption beds, carbon dioxide freezers, membranes,and centrifugal separators.
 12. A method for extracting fluids from aplanet's subsurface, comprising: bringing to a surface location, abovethe fluid in the planet's subsurface, a portable apparatus, the portableapparatus capable of reforming a fuel and injecting a compressed drivergas into the subsurface; reforming a fuel with water to produce a drivergas mixture including at least carbon dioxide gas and hydrogen gas;compressing a portion of the carbon dioxide gas and a portion of thehydrogen gas; injecting the portion of the carbon dioxide gas and theportion of the hydrogen gas compressed by the compressor, to apredetermined depth within the planet's subsurface; recapturing aportion of the carbon dioxide gas and the hydrogen gas that emerges fromthe subsurface with the fluid; re-injecting the captured portion of thecarbon dioxide gas and the captured portion of the hydrogen gas backinto the planet's subsurface; and controlling the injection usingsubsurface data.
 13. The method according to claim 12, furthercomprising: separating a portion of the hydrogen gas from the carbondioxide gas; and utilizing the separated portion of the hydrogen gas togenerate power.
 14. The method according to claim 12, wherein theportable apparatus is brought to the surface location above the fluid bya truck, a train, a water vessel, or an aircraft.
 15. The methodaccording to claim 12, wherein the fuel is selected from the groupconsisting of coal, coal/water slurries, crude oil, crop, forestryresidues, biomass, alcohols, natural gas, refined petroleum products,oil shale, tars, and industrial waste products.
 16. A system forrecovering fluid from Earth's subsurface, comprising: at least oneorifice leading to at least one hole; a fuel reformer, adapted to reacta fuel with water to produce driver gas; a compressor, adapted tocompress the driver gas; an injection line, operably connected to thecompressor and leading into the Earth's subsurface via the orifice,adapted to inject the driver gas to a predetermined depth down the hole;a gas capture unit, adapted to capture a portion of the driver gas thatreturns from the Earth's subsurface with the fluid; and a control modulecapable of using down-hole data to regulate operation of the compressor.17. The system according to claim 16, further comprising: a powergenerator adapted to utilize a portion of the driver gas to generatepower.
 18. The apparatus according to claim 17, wherein electrical poweris generated at or near the reservoir, and wherein the electrical poweris fed into an electrical grid.
 19. The apparatus according to claim 17,wherein the power is selected from the group consisting of electricalpower, mechanical power, and steam power.
 20. A system for recoveringoil from an oil field, comprising: at least one injection openingleading to at least one injection well; at least one production openingleading to at least one production well; a fuel reformer, adapted toreact a fuel with water to produce carbon dioxide gas and hydrogen gas;a compressor, adapted to compress a portion of the carbon dioxide gasand a portion of the hydrogen gas; an injection line, operably connectedto the compressor and leading down the injection well via the injectionopening, adapted to feed the driver gas to a predetermined depth withinthe oil field; a control module capable of using data from the oil fieldto regulate operation of the compressor; a gas capture unit, adapted torecapture a portion of the carbon dioxide gas and the hydrogen gas thatemerges with the oil from the production well; a recaptured gas pipeleading from the production well to the injection well to recycle therecaptured carbon dioxide gas and the recaptured hydrogen gas into theoil field via the injection well; and a power generator adapted toutilize a portion of the hydrogen gas to generate power.